## 1



# Entergy Response to EPA Region 6 comments on Entergy White Bluff draft BART Report

06/10/13

Entergy has reviewed the comments provided by EPA Region 6 on March 6, 2013 and appreciates the

opportunity to provide the below response. To simplify the format of this response, we have included

each of EPA’s comments, followed by our response. Submitted concurrently herewith is a revised FiveFactor Analysis (FFA) incorporating several revisions as discussed below.

SO 2 

# BART

x EPA Comment 1 - A BART evaluation requires that, “in analyzing the technology you take into

account the most stringent emission control level that the technology is capable of achieving” (70

FR 39166). ADEQ should demonstrate this requirement has been met. In particular, the BART

report for Entergy White Bluff states that wet scrubbers can achieve up to 95% control efficiency

at Units 1 and 2. It is also stated that discussions with vendors suggest that although a wet

scrubber may be able to achieve up to 97% control at units burning higher sulfur coal, this may

not be achievable for the low sulfur coal typically combusted at Units 1 and 2. The BART report

should include documentation from the vendor to corroborate this statement. Furthermore,

section 5.4 of the BART report indicates that semi-dry scrubbers were evaluated at an outlet SO 2



# emission rate of 0.06 lb/MMBtu and wet scrubbers at an outlet SO 2 

# emission rate of 0.04

lb/MMBtu. In section 5.4 it is stated that this represents 95% removal efficiency for the dry

scrubber option and 97% removal efficiency for the wet scrubber option when applied to the

units’ currently allowable SO 2 

# emission rate of 1.2 lb/MMBtu. Considering that the 2001-2003

average SO 2 

# emission rate is 0.81 lb/MMBtu at Unit 1 and 0.79 lb/MMBtu at Unit 2 (based on

information recently provided by Entergy), it appears that the actual removal efficiency

evaluated for the two control options at Units 1 and 2 is less than 95% for dry scrubbers and less

than 97% for wet scrubbers. Based on the annual SO 2 

# emissions reductions expected to result

from each control option (as shown in tables 5-7 and 5-8), it appears that dry scrubbers were

evaluated at 91.5% removal efficiency for Unit 1 and 90.5% for Unit 2 while wet scrubbers were

evaluated at 94.3% removal efficiency for Unit 1 and 93.7% for Unit 2. ADEQ should ensure

that the requirement to evaluate the most stringent emission control level the technology is

capable of achieving has been satisfied.

Entergy Response

– Entergy has evaluated available SO 2 

# emission control technologies and

believes that the level of control considered within the February 2013 FFA (and the June 2013

revised FFA) represents the most stringent level of control for each technology for the operating

conditions which exist at the White Bluff plant. It is also important to consider the inherent

variability of emissions over time and allow for a reasonable compliance margin in determining a

potential 30-day average emission limitation for evaluation in the FFA process.

Entergy commissioned a study in 2008 from Sargent & Lundy (S&L) to compare the control and

cost effectiveness of dry versus wet flue gas desulfurization (FGD) technologies. A copy of this

## 2



# study was previously provided along with our revised BART FFA submitted in 2008. For

reference, a copy of this study is included with this response as Attachment D. It should be

noted that the financial information included in this study is out-of-date and is not consistent

with more recent information which was relied upon in the 2013 FFAs.

In this study, S&L indicates that typical control efficiencies achieved by dry FGD range from

85% - 95% in real-world applications 1 

# , depending on the dry FGD inlet SO 2 

# concentration. A

chart is provided of typical SO 2 

# reduction efficiency as a function of inlet SO 2 

# emission rates (lb

SO 2 

# /MMBtu) 2 

# . Based on S&L’s data, the maximum SO 2 

# control efficiency (95%) is achieved at

an inlet SO 2 

# emission rate in the range of 1.8 to 3 lb/MMBtu). Expected control efficiencies for

inlet SO 2 

# emission rates similar to those at White Bluff Units 1 and 2 (0.6 to 1.2 lb SO 2 

# /MMBtu)

are in the range of 90-93%. This is consistent with the control efficiency evaluated within the

2013 FFA for semi-dry scrubbing, as documented in Tables 5-7 and 5-8. It is noted that the

control efficiencies calculated by EPA in its comments are based on a mix of the post-control 30-

day average emission rate and the pre-control 3-year average emission rate over the baseline

period. An “apples to apples” calculation based on the maximum 30-day average emission rate

during the baseline period (0.81 lb/MMBtu for Unit 1 and 0.79 lb/MMBtu for Unit 2) and the

post-control 30-day average emission rate (0.06 lb/MMBtu for each unit) results in control

efficiencies for semi-dry scrubbing of 92.6% for Unit 1 and 92.4% for Unit 2.

For wet FGD, the S&L study indicates that control efficiencies in the range of 95-99% are

achievable for units burning medium-to-high sulfur coals and efficiencies of 93-95% achievable

for units burning low-sulfur coals 3 

# such as that typically utilized by White Bluff Units 1 and 2.

As with dry FGD above, EPA is mixing 3-year average and 30-day average SO 2 

# emission rates

in calculating the control efficiency evaluated for wet FGD. Based on the maximum 30-day

average emission rate during the baseline period for each unit, and the post-control 30-day

average emission rate of 0.04 lb/MMBtu for wet FGD, the 2013 FFAs consider wet FGD at a

control efficiency of 95.06% for Unit 1 and 94.9% for Unit 2. This is consistent with the

information provided by S&L, and represents the most stringent level of control achievable by

this technology for the operating conditions present at White Bluff Units 1 and 2.

As outlined above, Entergy is considering the most stringent level of control achievable for Units

1 and 2 at White Bluff.

x EPA Comment 2

- The executive summary (section 1) of the BART report states that Entergy

has concluded that the installation of a semi-dry scrubber and baghouse is BART for SO 2 

# for

both Units 1 and 2. However, the SO 2 

# controls evaluated in the BART report are wet scrubbers

1 

## S&L Wet vs. Dry FGD Technology Study (October 2008), pg. 2-3, attached as Attachment D.

2 

## Id. at 2-3, Figure 2-1

3 

## Id. at 2-13.

## 3



# and semi-dry scrubbers, and no mention of a baghouse is made in the body of the BART report.

The cost evaluation of the dry scrubber option (in Appendix A) contains line items related to the

O&M costs of the baghouse, but there does not appear to be a line item for the baghouse capital

costs. Please specify whether the dry scrubbing technology evaluated and selected as BART is

NID or some configuration of SDA.

Entergy Response

–The semi-dry scrubbing evaluated and selected as BART is based on a

SDA system. However, Entergy is exploring both NID and SDA as potential technology

selections for SO 2 

# control. Both technologies are capable of similar levels of SO 2 

# emission

reduction. Either technology may be ultimately selected by Entergy if the proposed SO 2 

# BART

determination is approved by ADEQ.

The semi-dry scrubber cost estimate includes a baghouse. The cost estimate utilized for the 2013

FFAs was based on a vendor quote (Alstom) for an SDA system, including a baghouse. This

quote was obtained by Entergy in 2011 and was adjusted to 2012 dollars for the purposes of the

2013 FFAs. Additional details regarding the cost estimate for the semi-dry FGD system are

included with this response.

x EPA Comment 3

- In the cost evaluation of SO 2 

# controls Entergy assumed a 15 year equipment

life for both wet and semi-dry scrubbers, based on a misinterpretation of the EPA Control Cost

Manual (CCM). 4 

# EPA believes that 30 years is the more appropriate equipment life for

scrubbers. If Entergy believes that the remaining useful life of the boilers affects the BART

determination, then an equipment life less than 30 years may be assumed, but this would require

a federally enforceable restriction preventing further operation of the boilers by a date certain.

Scrubber vendors indicate that the lifetime of a scrubber is equal to the lifetime of the boiler,

which in some cases easily exceeds 60 years. The typical life for a scrubber is reported as 30

years in published papers and standard cost estimating handbooks. Since the capital costs are

annualized over a period of time equal to the anticipated equipment life, and then added to the

annual O&M costs to obtain the total annualized costs, the two SO 2 

# control options evaluated

will be more cost effective than what is estimated in Entergy’s cost evaluation if a 30 year

operating life is assumed.

Entergy Response – The assumed equipment life has been revised to 30 years. This change is

reflected in the costing tables presented in section 5 of the June 2013 revised FFA. Please note

that the capital recovery period does not affect the outcome of the BART determination in the

June 2013 revised FFA.

x EPA Comment 4

- In section 5.4.1, it is stated that the capital and O&M costs used in Entergy’s

cost effectiveness calculations for the wet scrubber option are based on vendor estimates for a

4 

## EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002; see

http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf.

## 4



# system designed to achieve 97% control (0.06 lb/MMBtu) for an inlet SO 2 

# rate of 2.0 lb/MMBtu,

and that the cost for a system designed to achieve an emission rate of 0.04 lb/MMBtu for an inlet

SO 2 

# rate of 1.2 lb/MMBtu would be approximately 5-6% higher. It does not appear that Units 1

and 2 have historically burned coal containing 1.2 lb/MMBtu SO 2 

# . To properly evaluate costeffectiveness, controls should either be designed to burn coal with the same sulfur content as has

been historically used at the units (2001-2003), or if the controls evaluated are designed to burn

coal with a higher sulfur content than has been historically used at the units, ADEQ should

ensure that the baseline is raised to correspond with the sulfur content of the type of coal the

scrubber has been designed to burn.

Entergy Response

–Entergy does not believe it is necessary to re-evaluate the selected

technology nor to adjust the baseline as the FFA was developed with consideration of the sulfur

content of the type of coal historically burned at the facility as well as that for which a scrubber

would be designed. As both units are subject to an emission limit of 1.2 lb SO 2 

# /MMBtu, it is not

possible for the baseline emission rate to exceed this level.

In initiating the effort to develop an updated FFA (from 2008) for Units 1 and 2 at the White

Bluff facility, Entergy considered both semi-dry and wet FGD to be equivalent technologies and

intended to evaluate only semi-dry FGD as the most stringent level of control available for SO 2



# emissions from Units 1 and 2. During Entergy’s efforts to prepare an updated FFA, feedback

was received that EPA Region 6 believed that wet FGD technologies were capable of a greater

level of control than that achievable by semi-dry FGD technologies, and that wet FGD should be

considered separately in a proper FFA. In order to address this concern, Entergy conducted a

review of existing studies of available SO 2 

# control technologies, and held discussions with S&L

on this topic. Based on this review, Entergy determined that a wet FGD system may be able to

achieve a slightly higher level of SO 2 

# control for Units 1 and 2. Entergy has received no

guarantees to this effect, but this assumption was utilized for the purposes of the February 2013

FFA. In order to facilitate Entergy’s ability to consider wet FGD within the FFA, a decision was

made to rely upon existing wet FGD cost estimates for Units 1 and 2. Since no cost estimate was

available specific to an outlet emission rate of 0.04 lb/MMBtu, S&L indicated that an existing

available estimate for 97% control at an inlet SO 2 

# emission rate of 2.0 lb/MMBtu would be

reasonably representative of the costs expected for a scrubber designed to achieve an outlet

emission rate of 0.04 lb/MMBtu for coals typically combusted at White Bluff Units 1 and 2.

On this basis, Entergy relied upon this existing available cost estimate for the purposes of the

FFA. As it is more difficult to achieve high levels of SO 2 

# reduction at lower SO 2 

# inlet emission

rates, such as those observed on White Bluff Units 1 and 2 during the 2001-2003 baseline period,

S&L estimated that a wet FGD system designed for an outlet emission rate of 0.04 lb/MMBtu

would be 5-6% higher than the estimate which was used for the purpose of the FFA. This

additional 5-6% was not

added to the cost estimate used within the FFA, but was noted within

the narrative of the document. Entergy believes the cost estimate utilized for the FFA represents

a conservative estimate of the cost of a wet FGD system designed for an outlet SO 2 

# emission rate

## 5



# of 0.04 lb/MMBtu for the units at White Bluff. A copy of the cost estimate utilized for purposes

of the FFA is provided with this response (Attachment C).

As Units 1 and 2 at White Bluff currently do not employ any post-combustion SO 2 

# controls,

Entergy primarily combusts low-sulfur coal in order to ensure an adequate margin of compliance

with the existing emission limit of 1.2 lb SO 2 

# /MMBtu. Installation of post-combustion SO 2



# controls, as proposed by the 2013 FFAs, will allow greater control of the SO 2 

# emission rate and

may allow for greater flexibility in fuel supplies. The cost estimate utilized by Entergy for the

purposes of the FFA was prepared by S&L in the course of investigating such potential options

for an SO 2 

# -controlled operating scenario.

x EPA Comment 5

- In section 5.6 the statement is made that EPA previously agreed that SDA

technology is BART for White Bluff Units 1 and 2

. 

# The statement makes reference to a letter

dated November 25, 2009, from Region 6 to ADEQ, in which comments were provided on the

draft Title V/Prevention of Significant Deterioration (PSD) permit for White Bluff. In that letter,

EPA agreed that dry scrubber technology is one of the SO 2 

# controls generally accepted as BART.

Although that statement, offered in another regulatory context, remains true, EPA action on a

state’s BART determination can only be made via rulemaking after public notice and comment.

Entergy Response

– Entergy notes that the cited comment from the Nov. 25, 2009, letter was

specific to Units 1 and 2 at White Bluff. The relevant statement reads as follows:

Specifically, for Units 1 and 2, BART for sulfur dioxide (SO2) was determined to

be the retrofit of a spray dryer absorber (SDA)/fabric filter dry flue gas

desulfurization system. While we agree that this technology is BART for these

two units, we do not believe that the emission rate of 0.15 pounds (lbs)/millions

British thermal units (MMBtu) is BART. 5



# The 2013 FFAs submitted by Entergy propose semi-dry FGD (such as SDA) as BART for both

Unit 1 and Unit 2, at a 30-day average emission rate of 0.06 lb SO 2 

# /MMBtu. This technology

and emission rate is consistent with EPA’s statements in the November 2009 letter.

x EPA Comment 6 - Entergy is proposing to use a semi-dry scrubber and a baghouse to satisfy

SO 2 

# BART at Units 1 and 2, which will involve replacing the existing ESPs with baghouses.

Since this will likely result in a higher PM removal efficiency than currently achieved by the

existing ESPs, ADEQ should re-evaluate the BART limits previously established for Units 1 and

2 and ensure that the limits still meet the criteria of being the most stringent limit reasonably

available.

5 

## Letter from Jeff Robinson, Chief, Air Permits Section, US EPA Region 6 to Thomas Rheaume, Air Permits Branch

Manager, ADEQ dated November 25, 2009.

## 6



# Entergy Response – ADEQ’s previous BART determination for PM from Units 1 and 2 at

White Bluff was approved by the EPA into the Arkansas SIP 6



# .

x EPA Comment 7 - The cost evaluations for SO 2 

# controls included undocumented costs, line

items that should be identified/explained, as well as some costs that are not allowed under the

CCM. According to the CCM, AFUDC costs are not allowed in estimating capital costs for

controls. In addition, for the semi-dry scrubber cost evaluation, please provide the following:

o a breakdown of costs for FGD equipment, FGD materials, BOP equipment, and BOP

materials;

o please explain which line item(s) account for the capital costs of the baghouse;

o the estimate should explain the need for the costs under FGD contractor contingency;

o The estimate should explain what expenses are accounted for under BOP indirect costs,

miscellaneous contractor labor, Entergy internal costs, and capital suspense.

For the wet scrubber cost evaluation, please provide a breakdown of total equipment costs,

purchased equipment cost, and direct annual costs.

Entergy Response

-

AFUDC:

Entergy disagrees with EPA that AFUDC should not be included as part of the costs of control

technology. The CCM does not preclude inclusion of AFUDC and, indeed, the formula included

in the CCM expressly includes AFUDC as a variable. The fact that the example used in the

CCM “assumes” that AFUDC is zero does not reflect a reasoned decision to exclude AFUDC.

The CCM expressly anticipates the inclusion of AFUDC where appropriate. Further, the CCM

clearly allows the inclusion of interest costs associated with the control technology. AFUDC is

nothing more that the interest expense on the investment in the technology that is incurred during

construction, before the equipment is placed in service. For major control technology

installations, such as scrubbers or SCR, the interest expense incurred during the 30 - 46 months

of construction can reach $30 million to $60 million for a large unit. AFUDC simply includes

the interest as part of the capital cost, which is standard accounting and rate-making treatment of

such costs.

Costs for Semi-dry Scrubbing:

Contractor Costs

Entergy has revised the February 2013 FFA report regarding contractor cost for semi-dry

scrubbing to reflect a 30-year equipment life. The revised report is provided under the same

cover as this question and answer document. The following summarizes the iterative process

Entergy followed for estimating the contractor costs for semi-dry scrubbing.

6 

## 77 FR 14675

## 7



# In early 2009, S&L provided Entergy a line-itemed cost estimate that included contractor

equipment, material, and labor costs for two semi-dry scrubbing systems. The total estimated

contractor cost was $291,930,000. The itemized costs are provided in Table A-1 of Attachment

A. Itemized baghouse costs were included.

In December 2009, Alstom provided Entergy with a “Milestone Payment Schedule”. The

payment schedule did not include itemized equipment cost, but; at the bottom of the schedule;

the value of Alstom’s contract with Entergy to supply two semi-dry scrubbing systems

($247,856,184) was specified. A copy of the payment schedule is provided in Attachment A to

this response. Note that the total contract price for the two semi-dry scrubbing systems included

in Alstom’s December 2009 payment schedule ($247,856,184) is less than the cost estimate

provided by S&L to Entergy in early 2009 ($291,930,000).

In early 2010, Entergy canceled the 2009 contract with Alstom for the supply of two semi-dry

scrubbing systems.

In 2010, Alstom informed Entergy that if Entergy subsequently were to continue with the

project, the 2009 contract price of $247,856,184 would increase by 10%. For purposes of the

BART analysis, Entergy relied on the lower contractor cost of $272,197,128 ($247,856,184 plus

the approximately 10% increase).

EPA asked for a breakdown of the equipment and material costs associated with the

$272,197,128 estimated cost for the February 2013 FFA. Alstom did not provide such

itemization. Thus, Entergy used the line-itemed cost information from early 2009 to estimate the

line-itemed cost for the total estimated cost of $272,197,128. Entergy took the total cost of

$272,197,128 and multiplied the total cost by the percentage of the total cost estimated for

equipment, materials, and labor. Entergy based the percentages of the total estimated cost

specific to equipment, materials, and labor on the early 2009 line-itemed cost estimate provided

by S&L as shown in Table A-1 of Attachment A (equipment = 42%, materials = 11%, labor =

47%.) This resulted in costs of $115,299,965 for equipment, $29,681,855 for materials and

$127,215,308 for labor.

Then, Entergy multiplied the estimated costs for equipment, materials, and labor by the

percentage of the cost estimated for each line item represented in the early 2009 cost estimate

provided by S&L. The percentages reflected in the early 2009 cost estimate were applied to the

revised cost estimates for equipment, materials, and labor described above in order to obtain

itemized costs that follow the itemization in the 2009 detailed estimate. The line item breakout

is provided in Table 1. Note that the estimated cost of $272,197,128, which was utilized in the

February 2013 FFA, is approximately 6.8% less than the early 2009 contractor cost estimate of

$291,930,000 provided to Entergy by S&L.

## 8

T ABLE 

## 1. B REAKDOWN OF 

## E QUIPMENT



## , M ATERIAL



## , AND LABOR 

## C OSTS FOR 

## S EMI



## - DRY



## S CRUBBING

Equipment Material Labor

2009 S&L Estimate Categorical Cost Percentages 42% 11% 47%

Applying percenages to 2010 Cost Estimate ($272,197,128) $ 115,299,965 $ 29,681,855 $ 127,215,308

Equipment Cost % of Total

Equip Cost Material Cost % of Total

Material Cost Labor Cost % of Total

Labor Cost

UNIT 1 ABSORBER AREA 22,575,191 $ 19.6% 958,795 $ 3.2% 12,205,592 $ 9.6%

UNIT 2 ABSORBER AREA 22,575,191 $ 19.6% 863,640 $ 2.9% 12,139,470 $ 9.5%

REAGENT PREP SYSTEM 11,254,673 $ 9.8% 9,062 $ 0.0% 8,096,705 $ 6.4%

WASTE RECYLING SYSTEM 4,443,550 $ 3.9%

- $

- 3,299,589 $ 2.6%

COMMON STRUCTURES AREA

- $ 2,157,741 $ 7.3% 1,815,100 $ 1.4%

REAGENT HANDLING SYSTEM

- $ 226,558 $ 0.8%

- $

-

UNIT 1 FLUE GAS SYSTEM 225,752 $ 0.2% 10,259,466 $ 34.6% 15,931,715 $ 12.5%

UNIT 2 FLUE GAS SYSTEM 225,752 $ 0.2% 10,259,466 $ 34.6% 15,931,715 $ 12.5%

UNIT 1 BOOSTER FANS 5,361,608 $ 4.7%

- $

- 138,763 $ 0.1%

UNIT 2 BOOSTER FANS 5,361,608 $ 4.7%

- $

- 138,763 $ 0.1%

UNIT 1 NEW BAGHOUSE 20,693,925 $ 17.9%

- $

- 7,917,896 $ 6.2%

UNIT 2 NEW BAGHOUSE 20,693,925 $ 17.9%

- $

- 7,917,896 $ 6.2%

INSTRUMENTATION 1,888,791 $ 1.6%

- $

- 176,947 $ 0.1%

MOBILIZE/DEMOBILIZE

- $ 857,725 $ 0.7%

OVERTIME

- $ 12,068,691 $ 9.5%

PER DIEM

- $ 11,942,034 $ 9.4%

FREIGHT 1,237,008 $ 4.2%

- $

GENERAL & ADMINISTRATION 1,237,008 $ 4.2% 5,545,880 $ 4.4%

PROFIT 2,473,110 $ 8.3% 11,090,828 $ 8.7%

UNIT 2 BOOSTER FANS

UNIT 1 BAGHOUSE

UNIT 2 BAGHOUSE

SITE IMPROVEMENTS

MECHANICAL MISCELLANEOUS

PIPE RACK

DEMOLITION COSTS

ELECTRICAL

Total Estimated Costs 115,299,965 $ 29,681,855 $ 127,215,308 $

Total Estimated Costs: Equipment, Material & Labor

Total Estimated Costs, Per Unit 57,649,983 $ 14,840,928 $ 63,607,654 $ Total Cost for Equipment, Materials, and Labor from 2009 Alstrom Cost Estimate with 10% Escalation 272,197,128 $

272,197,128 $



# BOP Costs

In 2008, S&L provided information on the balance of plant (“BOP”) equipment, materials, and

labor costs to Entergy. The breakout of the 2008 BOP equipment, materials, and labor cost is

provided in Attachment B. In using the 2008 BOP costs as part of the cost estimate for semi-dry

scrubbing, Entergy escalated the costs from 2008 dollars to 2012 dollars.

## 9 T ABLE 

## 2: BOP E QUIPMENT AND 

## M ATERIALS SUMMARY



## , S EMI 

## -D RY 

## S CRUBBING



# Cost Included in

BART Submittal Cost from 2008

S&L Quote Cost Based on

Entergy Escalation

of 2008 S&L Quote

to 2012 Dollars

BOP Total Equipment Costs $ 49,632,641 $ 46,037,000 $ 3,595,641

BOP Total Material Costs $ 52,928,270 $ 42,144,000 $ 10,784,270



# Please note that in reviewing the 2008 S&L data for this response it was discovered that the BOP

costs presented in the February 2013 FFA as being in 2008 dollars were actually in 2012 dollars.

Thus, the costs should not have been escalated from 2008 to 2012 dollars, as they were in the

BART analysis. Entergy has revised the costing to subtract the extra $14,379,412 from the BOP

costs. This revision is reflected in the June 2013 revised FFA.

Contingency

FGD contingency was calculated as 15% of the total FGD costs, and was included to account for

change orders and risks such as regulatory, environmental (e.g. fly ash classification as a

hazardous material) and underground interference that would have an impact on the baghouse or

FGD structure. The CCM clearly allows for contingency costs on page 2-30, as long as in using

the contingency factor no “double penalty” is imposed on the system. The CCM continues, “A

contingency factor should be reserved (and applied to) only those items that could incur a

reasonable but unanticipated increase but are not directly related to the demolition, fabrication,

and installation of the system.” Entergy took this guidance into consideration when developing

the contingency estimate.

BOP Indirect Costs

BOP indirect costs are costs associated with engineering, construction management, startup and

commissioning and are estimates provided by the contractor. Miscellaneous contractor labor is

inclusive of legal support, owner’s insurance, S&L engineering costs, and Entergy’s

environmental permitting costs. Entergy internal costs include ESI labor, construction site labor,

travel and loader costs.

Capital Suspense

Capital suspense is a distribution of overhead costs associated with administrators, engineers,

and supervisors and includes function specific rates and A&G (Corporate Accounting) rates.

Function specific capital suspense is dependent upon the personal hours allocated to a specific

project for a time period. However, the percent of a total project that is dedicated to capital

suspense is not a constant. Rather, it is dependent upon the yearly total capital expense budget

and the budgeted capital spending for a specific function. Based on Entergy’s experience with

hours required in similar projects, a 2% of total capital has been assumed to represent the future

capital suspense of the project.

## 10



# Costs for Wet Scrubbing:

Costs for Wet Scrubbing were provided in a 2012 estimate from S&L which is provided as

Attachment C to this submittal. The total equipment cost (EC) was calculated by taking the total

projected costs (equipment and labor) and subtracting the total construction and erection costs

from the estimate. These costs are summarized below in Table 3.

## 11

T ABLE 

## 3: S ARGENT 

## & L UNDY 

## 2012 T OTAL 

## E QUIPMENT AND 

## P URCHASED 

## E QUIPMENT 

## C OSTS DETAILS



## , W ET



## S CRUBBING



# Item Total Construction &

Erection Cost Total Projected Cost

(Equipment and

Labor) Total Equipment

Costs (EC) (Total

Projected Cost - Total

Construction and

Erection Cost)

1.0 ID FANS

11,356,500 $ 36,229,400

$ 24,872,900

$

2.0 NEW STACK

- $ 40,924,000

$ 40,924,000

$

3.0 LIMESTONE HANDLING SYSTEM

9,183,200 $ 20,096,900

$ 10,913,700

$

4.0 REAGENT PREPARATION ISLAND

14,003,200 $ 35,456,200

$ 21,453,000

$

5.0 BYPRODUCT DEWATERING ISLAND

12,824,900 $ 28,730,000

$ 15,905,100

$

6.0 ABSORBER ISLAND

101,468,300 $ 254,576,500

$ 153,108,200

$

7.0 FGD WASTE WATER TREATMENT PLANT

9,827,600 $ 25,159,500

$ 15,331,900

$

8.0 COMPRESSED AIR SYSTEM

709,600 $ 1,700,400

$ 990,800

$

9.0 SERVICE WATER SYSTEM

2,468,600 $ 4,932,300

$ 2,463,700

$

10.0 POTABLE WATER SYSTEM

301,900 $ 608,400

$ 306,500

$

11.0 ELECTRICAL (AUX POWER)

720,500 $ 2,781,300

$ 2,060,800

$

12.0 FGD DCS SYSTEM

1,929,900 $ 7,566,500

$ 5,636,600

$

14.0 RAIL INFRASTRUCTURE

773,100 $ 1,970,700

$ 1,197,600

$

15.0 SITE IMPROVEMENTS - CIVIL WORK

3,591,900 $ 6,906,700

$ 3,314,800

$

16.0 BOP ITEMS

1,830,300 $ 3,424,700

$ 1,594,400

$

17.0 DEMOLITION

410,400 $ 410,400

$

-

$

300,074,000 $

150,037,000 $ Total Equipment Cost, Unit 1 & Unit 2

Per Unit Total Equipment Cost

## 12



# Cost for the Purchased Equipment Cost (PEC) for wet scrubbing is calculated based on the CCM

guidance of PEC = 1.18*EC, where EC = $150,037,000, as shown in Table 4. PEC = 1.18*

$150,037,000 = $177,043,660.

Direct annual costs for wet scrubbing were estimated by S&L in 2011 and are summarized in

Table 4.

T ABLE 

## 4: S ARGENT 

## & L UNDY 

## 2011 D IRECT 

## A NNUAL 

## C OSTS FOR 

## W ET 

## S CRUBBING



# 1,513,000 $

3,378,000 $

5,067,000 $

13,639,000 $

4,038,000 $

863,000 $

2,971,000 $

Total Direct Annual Costs 31,469,000 $

Total Direct Annual Costs, Per Unit 15,734,500 $ Limestone

Waste Ash Disposal Materials and Supplies Fixed O&M

Variable O&M Operating Labor

Maintenance Labor

Aux Power

Total Water Requirement



# NO

x 

# BART

x EPA Comment 8 - Although FGR is identified as a technically feasible NO

x 

# control option in

sections 6.1 and 6.2 of the BART report, ADEQ should either justify why this control option is

subsequently dropped from consideration in the remainder of the BART report, or include it in

the BART analysis.

Entergy Response – Based on information provided by S&L in their NOx study report, FGR

was not anticipated to be a viable NOx control option at White Bluff. The S&L study provides

the following information regarding FGR.

NOx reduction efficiency data for coal-fired units with FGR are limited. The amount of

NOx reduction achievable with FGR depends primarily on the fuel nitrogen content and

amount of FGR used. Generally, FGR is more effective when used with low nitrogen

content fuels such as natural gas and propane, since FGR is more effective in controlling

thermal NOx rather than fuel NOx. Industry experience with FGR on coal-fired units for

steam temperature control has shown very high maintenance on the gas recirculation fans

due to erosion and corrosion. Many of the units with FGR for steam temperature control

have removed the recirculation fans from service. The NOx control achievable on

tangentially fired units like White Bluff – Units 1&2 with LNB+OFA has been

comparable to that of FGR at lower capital and O&M cost. Currently, FGR technology is

not offered by OEMs for coal-fired units. For these reasons, FGR is not a feasible

technology for the White Bluff coal-fired units.

## 13



# The June 2013 revised FFA includes a discussion of FGR and a statement that FGR is not a

feasible technology for White Bluff Units 1 and 2.

x EPA Comment 9 - In Tables 6-7 and 6-8, Entergy indicates that it evaluated LNB/SOFA to

achieve 51% control at Unit 1 and 58% control at Unit 2. However, based on the annual NO

x 

# emissions reductions expected to result from LNB/SOFA, it appears that this control scenario

was evaluated at a removal efficiency of only 42.8% at Unit 1 and 50.4% at Unit 2. Similarly, it

appears that the removal efficiencies evaluated for the other two NOx control scenarios may be

lower than what is stated in Tables 6-7 and 6-8. ADEQ should either explain the discrepancy or

revise Tables 6-7 and 6-8 such that the estimated annual emissions reductions match up with the

control efficiency for each control scenario. ADEQ should ensure that the most stringent

emission control level that the technology is capable of achieving has been taken into account

(70 FR 39166).

Entergy Response

– Entergy believes that the February 2013 FFA evaluates the most stringent

emission control level that the technology is capable of achieving. As noted above for the SO 2



# control evaluations, EPA is mixing annual average emission rates during the baseline period with

proposed 30-day average post-control emission rates. An “apples-to-apples” comparison of the

maximum 30-day average emission rates during the 2009-2011 baseline period (0.31 lb/MMBtu

for Unit 1 and 0.36 lb/MMBtu for Unit 2) and the proposed post-control 30-day average

emission rate of 0.15 lb/MMBtu for each unit results in calculated control efficiencies of 51.6%

for Unit 1 and 58.3% for Unit 2, consistent with the values provided in Tables 6-7 and 6-8 of the

FFA.

x EPA Comment 10 - Please provide a copy of the “2012 S&L NOx Study” referred to in

footnotes 36-38. The emission rates evaluated for each NOx control scenario and the estimates

for capital costs, fixed O&M costs, and some of the variable O&M costs for NOx controls were

based on this study. This documentation should be included in the proposed SIP.

Entergy Response – S&L has provided an updated study on May 16, 2013. A copy of this

updated study is included as Appendix E to the June 2013 revised FFA. Please note that the

variable O&M costs presented in the February 2013 FFA were incorrectly calculated based on an

annual capacity factor of 100% for each unit. The variable O&M cost estimates contained within

the revised May 16, 2013 NOx study reflect an annual capacity factor of 76% for each unit,

which represents a conservative estimate of anticipated actual future annual capacity factors.

The revised FFA submitted along with this response reflects these corrected estimates of

anticipated variable O&M costs.

## 14



# x EPA Comment 11 - As was done in the cost evaluation of SO 2 

# controls, AFUDC costs were

included in the cost analysis of NOx controls. According to the CCM, AFUDC costs are not

allowed in estimating capital costs for controls.

Entergy Response

– See Entergy’s response to EPA Comment 7 above regarding AFUDC.

x EPA Comment 12 - In the cost evaluation of NOx controls Entergy assumed a 20 year

equipment life for SCR and SNCR. Unless proper documentation is provided to demonstrate that

the anticipated equipment life of SCR and SNCR is limited to 20 years, we believe that an

anticipated 30 year equipment life would be more appropriate to use in the cost analysis. If

Entergy believes that the remaining useful life of the boilers affects the BART determination,

then an equipment life less than 30 years may be assumed, but this would require a federally

enforceable restriction preventing further operation of the boilers by a date certain.

Entergy Response – The assumed equipment life has been revised to 30 years. This change is

reflected in the costing tables presented in section 6 of the June 2013 revised FFA. Please note

that the capital recovery period does not affect the outcome of the BART determination in the

2013 FFA.

Auxiliary Boiler (SN-05)

x EPA Comment 13 - Please provide modeling files for baseline modeling for SN-05 as well as

baseline modeling for the three subject-to-BART units combined.

Entergy Response- The baseline modeling files for SN-05 have been uploaded to same the ftp

site that contains the modeling files specific to SN-01 and SN-02 (ftp.trinityconsultants.com

, username = Entergy, password = Trinity).

There are no baseline modeling files that consider the cumulative impact of SN-01, SN-02, and

SN-05. Modeling to determine the cumulative impact is not needed as part of making sourcespecific BART determinations. Since the impact of SN-01 and SN-02 by themselves is over 0.5

ǻ dv, it is clear that the cumulative impact of SN-01, SN-02, and SN-05 would also be over 0.5

ǻ dv.

x EPA Comment 14 - Please explain how baseline maximum 24-hr emissions for SN-05 were

calculated. We note that the modeled emissions for SO 2 

# of 5.8 lb/hr differ from the baseline

emission rate modeled in the SIP of 32.5 lb/hr.

Entergy Response

- The maximum short term baseline emission rates for SN-05 were calculated

using AP-42, Chapter 1, Section 1.3, Tables 1.3-1, 1.3-2, and 1.3-3. The emission factors in

these tables were multiplied by the maximum heat input rate for SN-05 of 183 MMBtu/hr. With

## 15



# respect to the SO 2 

# , the AP-42 emission factor in lbs/Mgal for No. 2 oil-fired boilers is 142 times

the weight percent sulfur in the fuel oil. The average percent sulfur in the fuel oil combusted in

SN-05 for the baseline years 2009-2011 was 0.031% (2009 = 0.043%, 2010 = 0.036%, and 2011

= 0.013%). This results in an SO 2 

# emission factor of 4.402 lb/Mgal. The factor was converted

to lb/MMBtu by dividing the factor by the average heat content of the fuel oil from 2009-2011 in

MMBtu/Mgal. The average heat content of the fuel from 2009-2011 was 138.409 MMBtu/Mgal

(2009 = 138.708 MMBtu/Mgal, 2010 = 138.404 MMBtu/Mgal, and 2011 = 138.116

MMBtu/Mgal). The SO 2 

# emissions factor in lb/MMBtu was multiplied by the maximum heat

rate for the boiler (183 MMBtu/hr) to obtain an emission rate of 5.8 lb/hr.

x EPA Comment 15 - Are there any limitations to the hours of operation of this unit? What are the

historical hours of operation of this unit? ADEQ should explain why the baseline is

representative of this unit’s history, as discussed in 40 CFR Part 51 Appendix Y (section

IV.D.4.d).

Entergy Response- Auxiliary boilers are typically utilized to provide steam to a main boiler

during startup. Thus, the operating hours for auxiliary boilers typically coincide with the startup

hours for a boiler. Entergy operates SN-05 to provide steam to SN-01 and SN-02 during startup

when both units are offline, and, in extreme situations, can provide steam to the auxiliary steam

system. SN-05 is not currently subject to any limit on annual operating hours. Actual annual

hours of operation for the aux boiler are summarized in the table below for the 2005-2012

period. Aux. boiler operating hours were not directly tracked by the facility prior to 2005.

T ABLE 

## 5: A CTUAL 

## A NNUAL 

## H OURS OF 

## O PERATION FOR 

## A UX 

## B OILER



## , 2005-2012



# Aux Boiler Operating Hours (hours/year)

2005 2006 2007 2008 2009 2010 2011 2012

14 16 89 2.15 63 46 51.5 83.3

EPA’s BART guidelines stipulate that enforceable limitations on hours of operation or unit

capacity are only required in situations where projected future values for these parameters differ

from past practice and this projection has a deciding effect on the BART determination 7



# . Entergy projects that future operation of the Aux. boiler will be consistent with past practice thus

no such restrictions are necessary.

x EPA Comment 16 - The White Bluff BART analysis states: “Since baseline visibility modeling

showed that there is no opportunity for visibility improvement attributable to SN-05, because not

a single day greater than 0.5 ǻ dv is associated with SN-05, it is not possible to install control

equipment to improve visibility. Therefore, no controls is the SO 2 

# BART (NOx BART)

7 

## 70 FR 39167

## 16



# determination for SN-05.” This is not an appropriate justification for not completing a BART

analysis for the unit. The 0.5 dv threshold applies only to the determination of whether the

facility, considering all BART eligible units, is subject to BART. 8 

# We note that in some cases,

states may adopt a more streamlined approach to making BART determinations where

appropriate. For example, a State need not undertake an exhaustive analysis where it is clear that

controls would be costly and any improvements in visibility resulting from reductions in

emissions would be negligible.

Entergy Response

- The maximum visibility impairment predicted by the CALPUFF modeling

system for SN-05 is only 0.036 ǻ dv. This is an extremely low level of impairment, so low that it

is likely falls within the level of accuracy that can be attributed to CALPUFF. In addition, this

modeling assumes that the auxiliary boiler operates at the maximum daily emission rate 365 days

per year. Since the existing visibility impairment predicted by CALPUFF is extremely low, to

the point of practically being nonexistent, the impairment cannot be considered significant such

as to require controls. Said another way, the impairment is so low that any improvement from

reductions would be less than negligible. Thus, no controls have been considered for SN-05.

Emission Estimation and modeling

x EPA Comment 17 - To estimate sulfuric acid emissions to model for the baseline and control

cases, all inorganic PM was assumed to be SO 4 

# . This assumption and assumptions of SO 4



# reductions due to controls impacts the baseline modeling as well as the visibility benefit from

WFGD when compared to NID. We recommend that sulfuric acid emissions from power plants

are calculated by estimating the amount of H 2 

# SO 4 

# produced and the amount of H 2 

# SO 4 

# removed

by control equipment using information from the Electric Power Research Institute (EPRI)

Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Version 2010a. EPRI,

Palo Alto, CA: 2010. 1020636, consistent with the methodology detailed in the Technical

support document that accompanies the Oklahoma FIP. Rather than assuming that 100% of

inorganic condensable PM is SO 4 

# , the EPRI method estimates the amount of SO 2 

# that is oxidized

to SO 3 

# and then assumes that 100% of SO 3 

# is converted to H 2 

# SO 4 

# . This methodology also

accounts for loss of sulfuric acid due to downstream equipment, such as the air pre-heater, ESP

or FF, and scrubber.

8 

## As explained by the preamble of the RHR: ‘‘Failing to consider less-than-perceptible contributions to visibility impairment

would ignore the CAA’s intent to have BART requirements apply to sources that contribute to, as well as cause, such

impairment.’’ 70 FR 39104, at 39129. Given that sources are subject to BART based on a contribution threshold of no

greater than 0.5 deciviews, it would be inconsistent to automatically rule out additional controls where the improvement in

visibility may be less than 1.0 deciview or even 0.5 deciviews. A perceptible visibility improvement is not a requirement of

the BART determination because visibility improvements that are not perceptible may still be determined to be significant.

## 17



# Entergy Response - When using the EPRI methodology, the SO 4 

# baseline emission rates for

SN-01 and SN-02 are lower than the SO 4 

# emission rates that were included in the February 2013

FFA based on the use of the NPS speciation profile. For SN-01, the NPS speciation profile gives

36.77 lb/hr and the EPRI approach gives 5.85 lb/hr. For SN-02, the NPS speciation profile gives

36.77 lb/hr and the EPRI approach gives 5.90 lb/hr.

The SO 4 

# rates based on the EPRI approach were calculated as follows:

SO 4 

# (lb/hr) = SO 2 

# (lb/hr)* K factor (98.07/64.04) * Fuel Impact Factor (Subituminous coal =

0.0019) * F2 air heater factor (0.36) * F2 ESP Factor (0.72)

Further, using the EPRI F2 factors which represent the fraction of the baseline SO 4 

# that will

remain based on the application of specific control devices, it is clear that dry FGD systems

remove significantly more SO 4 

# than wet FGD systems. The SO 4 

# F2 Factors in Table 4-5 of the

EPRI guidance are 0.40 for wet FGD and 0.01 for dry FGD.

Overall, SO 4 

# emissions based on the application of either wet FGD systems or dry FGD systems

will be lower than baseline. Further, dry FGD systems will remove more SO 4 

# than wet FGD

systems. Thus, the relationship for the reduction in baseline SO 4 

# based on the use of wet or dry

FGD from the February 2013 FFA is still relevant. While CALPUFF modeling using SO 4 

# rates

based on the EPRI approach rather than the NPS speciation profile would be expected to make a

very slight impact on the level of visibility improvement predicted by CALPUFF for wet and dry

FGD systems, the modeling would have no impact on the February 2013 FFA’s BART

determination.

x EPA Comment 18 - Total PM 10 

# emissions should be estimated based on current PM emissions

and the anticipated control efficiency or vendor guarantee of the proposed control equipment.

The appropriate NPS worksheet and coal characteristics should be utilized to determine

speciation (PMC, PMF, EC and SOA) given the total PM 10 

# emissions (or filterable PM10). We

note that if White Bluff upgrades the PM controls, the PM emission limit should be adjusted

accordingly.

Entergy Response - EPA’s Approval and Promulgation of Implementation Plans, published

March 12, 2012 9 

# , determined that the currently installed ESP is BART for PM 10 

# for SN-01 and

SN-02 with a limit of 0.10 lb/MMBtu. As such, it is not necessary to evaluate further reductions

to PM 10



# .

9 

## 77FR 14675

# ATTACHMENT A: SUPPORTING DOCUMENTATION FOR SEMI-DRY SCRUBBING

COSTS

## T ABLE 

## A-1. S ARGENT 

## & L UNDY 

## 2009 CONTRACTOR EQUIPMENT



## , MATERIAL AND LABOR 

## E STIMATED COSTS

DETAIL



## , S EMI



## - DRY 

## S CRUBBING

Equipment Cost % of Total

Equip Cost Material Cost % of Total

Material Cost Labor Cost % of Total

Labor Cost

UNIT 1 ABSORBER AREA 24,000,000 $ 19.6% 1,058,000 $ 3.2% 13,106,000 $ 9.6%

UNIT 2 ABSORBER AREA 24,000,000 $ 19.6% 953,000 $ 2.9% 13,035,000 $ 9.5%

REAGENT PREP SYSTEM 11,965,000 $ 9.8% 10,000 $ 0.0% 8,694,000 $ 6.4%

WASTE RECYLING SYSTEM 4,724,000 $ 3.9%

- $

- 3,543,000 $ 2.6%

COMMON STRUCTURES AREA

- $ 2,381,000 $ 7.3% 1,949,000 $ 1.4%

REAGENT HANDLING SYSTEM

- $ 250,000 $ 0.8%

- $

-

UNIT 1 FLUE GAS SYSTEM 240,000 $ 0.2% 11,321,000 $ 34.6% 17,107,000 $ 12.5%

UNIT 2 FLUE GAS SYSTEM 240,000 $ 0.2% 11,321,000 $ 34.6% 17,107,000 $ 12.5%

UNIT 1 BOOSTER FANS 5,700,000 $ 4.7%

- $

- 149,000 $ 0.1%

UNIT 2 BOOSTER FANS 5,700,000 $ 4.7%

- $

- 149,000 $ 0.1%

UNIT 1 NEW BAGHOUSE 22,000,000 $ 17.9%

- $

- 8,502,000 $ 6.2%

UNIT 2 NEW BAGHOUSE 22,000,000 $ 17.9%

- $

- 8,502,000 $ 6.2%

INSTRUMENTATION 2,008,000 $ 1.6%

- $

- 190,000 $ 0.1%

MOBILIZE/DEMOBILIZE 921,000 $ 0.7%

OVERTIME 12,959,000 $ 9.5%

PER DIEM 12,823,000 $ 9.4%

FREIGHT 1,365,000 $ 4.2%

GENERAL & ADMINISTRATION 1,365,000 $ 4.2% 5,955,000 $ 4.4%

PROFIT 2,729,000 $ 8.3% 11,909,000 $ 8.7%

UNIT 2 BOOSTER FANS

UNIT 1 BAGHOUSE

UNIT 2 BAGHOUSE

SITE IMPROVEMENTS

MECHANICAL MISCELLANEOUS

PIPE RACK

DEMOLITION COSTS

ELECTRICAL

Total Estimated Costs 122,577,000 $ 32,753,000 $ 136,600,000 $

Total Estimated Costs: Equipment, Material & Labor

Percentage of Total Estimated Cost 42% 11% 47%

Total Estimated Costs, Per Unit 61,288,500 $ 16,376,500 $ 68,300,000 $ Total Cost for Equipment, Materials, and Labor from 2009 S&L Cost Estimate 291,930,000 $

291,930,000 $



# Relationship between Table A-1 to Table 2 – In order to develop the itemized cost shown in

Table 2 of this response, the cost for each item shown in Table A-1 was multiplied by the ratio of

the “newer” categorical costs (equipment, material, or labor) to the “older” categorical costs. For

example, the line item breakout presented in Table 2 for the Unit 1 Absorber Area was derived:

Submitted Equipment Cost = $24,000,000 * $115,299,965 / $122,577,000 = $22,575,191

Submitted Material Cost = $1,058,000 * $29,681,855 / $32,753,000 = $958,795

Submitted Labor Cost = $13,106,000 * $127,215,308 / $127,215,308 = $12,205,592AftachmentA-I-MilestonePaymentScheduleWhiteBluffUnitI&2DFGDProjectCombinedAlstom/ZHIPaymentScheduleRev.Date-DecemberII,2009MonthDateMilestone1Description1Sep-09EntergyAwardDryFGOContractExecutionDryFGDPurchaseOrderissuedbyOwnerandacknowedgedbyuoplier2Oct-09InitialDesignInformationfromDryFGDSupplierProjectSpecif’cProcessFlowDagramsandMassBalances.ssuedforOwnerreviewParentcompanyGuaranteeDocumentSigneddocument3Nov-09IrtiaI_Des.gn_IrforTator_from_Dry_FGD_Supplie’P’cject_spec’ic_General_Arrargerreni_Drawings__ssucd_‘Cr_O.vrer_rev_e___________4Dec-09InitialDesignInformation‘rornDryFGDSupplerProjectspecficP&lDsissuedforOwner-ev’e________NTELoadDiag’arnsSDAandFFissuedforOwnerreview5Jan-10Award-BoosterFansPurchaseOrderIssuedforboosterfansandLubeOilcoolingsystemsDesignInformationfrcmDryFGDSupplierFirstreleaseof3DCADGeneralArrangementmodel,issuedforOwner___________________________________________________________________reviewFERCRetirementInformation-Preliminary________________________0.0#1:BoosterFanSelection-AwardBoosterFanSelection-Award,ward-FabricFilterBagsandCagesPurchaseOrder-issuedforFFbagsandcagesDO.ff1:RemoveBWFasBagSupplier-AwardRemoveBWFasBagSupplier-AwardBagslueGasDuctwork-StartofFabricationFabricationhascommencedforductwork3tructuralSteel-StartofFabricationFabricationhascommencedforstructuralsteelmembers0.87000%$2,161,2661.34000%$3,328,847$(200,000)$(300,000)$27,950$41,925r,QnnnDO.#1:RemoveBWFasBagSupplier-ReleasedforFabricationRemoveBWFasBagSupplier-ReleasedforFabrication)esignInformationfromDryFGDSupplierPhysicalflowmodelcompletedandreportissuedforOwnerreview2.38000%MonthlyInvoiceAmount(%)MonthlyInvoiceAmount($)3cumulativeInvoicedAmount(%)2CumulativeInvoicedAmount($)2IndividualMilestoneValue(%)CO#1IndividualMilestoneValue($)15Nov-1010,930,54316Dec-106Feb-10NTELoadDiagramsBoosterfansandmotors,issuedforOwnerreview04500%$1,117,8964.8500%$12,048,4400.22500Y$558,948Award-AtomizersPurchaseOrderissuedforatomizerassemblies0.225005’$558,9487Mar-10Award-LimesystemPurchaseOrderissuedforlimestorageandpreparationsystem—6.2400%$15,501,49711.0900%$27,549,9373.12000°/$7,750,749InitialDesignInformationfromDryFGDSupplierProjectspecificEquipmentList,issuedforOwnerreview3.12000°!$7,750,7490.0.#1:BoosterFanSelection-ReleasedforFabricationBoosterFanSelection-ReleasedforFabrication0.0.#1:AutomatedStockValves-AwardAutomatedStockValves-Award—-8Apr-10FlueGasDuctworkProcurementInitiatedPurchaseOrderissuedforSDAshell/casing0.4500%$1,117,89611.5400%$28,667,8330.45000%$1,117,8969May-i0NTELoadDiagramsLimestorageandpreparationsystem,issuedforOwnerreview0.4500%$1,117,89611.9900%$29,785,7300.22500%$558,948nitialEl&CDesignInformationProjectspecificProcessControlDescription,issuedforOwnerreview0.22500%$558,94810Jun-10FlueGasDuctworkProcurementInitiatedPurchaseOrderissuedforUnit1SDAinletduct—2.2600%$5,614,32414.2500%$35,400,0542.26000$5,614,324iiJul-10StructuralSteelProcurementInitiatedPurchaseOrderissuedforSDAstructuralsupportsteel0.4500%$1,117,89614.7000%$36,517,9510.45000$1,117,89612Aug-10StructuralSteelFabricationScheduleCompleteScheduleforfabrication,issuedforOwnerreview0.4500%$1,117,89615.1500%$37,635,8470.45000$1117,8960.0.#1:AutomatedStockValves-ReleasedforFabricationAutomatedStockValves-ReleasedforFabrication13Sep-i0SDADesignDrawingsSDAAccessSteelDrawings(ReleasedforFabrication)—4.0700%$10,110,75219.2200%$47,746,6002.03500/$5,055,376FabricFilterDesignDrawings,FabricFilterAccessSteelDrawings(ReleasedforFabrication)2.03500$5,055,37614Oct-10Award-DOSPurchaseOrderissuedfor131050.4500%$1,117,89619.6700%$48,864,4960.45000$1,117,89617Jan-il2.6800%$6,657,690.5700%22.3500°,$1.416.0022.3800%$55,522,190$22.9200%S5,912,43C1.3400C56.938,19325.3000%S$3,328,84718Feb-ilReceivePermitsforConstructionRequiredTierTwoReportssubmitted(ARDeptofEmergencyManagement),0.7000%$1,738,95026.0000%$64,589,5730.70000%$1,738,950AirSpaceObstructionpermitreceivedforcranes>200ft.(FAA),SpillPreventionControlandCountermeasurePlandevelopedandreadyforimplementation19Mar-ilMobilizeOn-SiteProjectManagerandSafetyManagerarefulltimepresenceon-site2.6700%$6,632,85228.6700%$71,222,4252.67000%$6,632,85220Apr-lIUnit1SDADeliverySDAringgirderandconesectionforUnit1areonsiteandplacedin2.9900%$7,427.80131.6600%$78.650,2261.49500%$3713.900storage/laydownarea—OfficeComplexandFabncationAreasSet-upOfficetrailerssetwithelectncalandplumbingfunctional.Feb-cationsite1.49500%$3713.900[surfa”esestablshedandeveit.i’-3r’i’-B0”ras,,‘4ce“—‘‘va‘e—‘/‘°I3-‘C‘‘-‘—,,,171000%S1.2800762,850,6230.57000%Si.416.002$5,912,430UntSDAStruc:u-raSeeDei.veryUntSDAsructurasee:aonseardpacecrIrestoage.-aydoooare3Unit1DuctdeliveryUnit1ductworksections(50%)areonsiteUnit1SDA-ASupportSteelErectionCompleteSteeliserected,plumb,andboltedC.O.1:Booster_FanSelection-DeliveryBoosterFanSelection-iJeilvefy________BaSoicrBaDcie$1.13v’a47433.974.7431.60000%53.974.7431.60000%$3,974,743$69,875$1500.000)$147.500AttachmentA-I-MilestonePaymentScheduleWhiteBluffUnitI&2DFGDProjectCombinedAlstomIZHlPaymentScheduleRev.Date-DecemberII,200923Jul-11Unit1SDAAInletDuctSuonortSteelComoleteUnit2DuctdeliverySteeliserected,olumb.andboltedUnit2ductworksections(50%)areonsite3.9900%$991201545.5800%$1132304901.33000%1.33000%$3304005$3304005Unit1FabricFilterStructuralSteelDeliveryUnit1fabricfiltergridsteelandstructuralsupportsteelisonsteandplacedinstorage/laydownarea—MonthDateMilestone1DescriptionMonthlyInvoiceMonthlyInvoiceCumulativeCumulativeIndividualIndividualCO#1Amount(%)Amount($)3InvoicedInvoicedMilestoneValueMilestoneValueAmount(%)2Amount($)2(%)($)1.33000%$330400524Aug-i1Unit2SDADeliverySDAringgirderandconesectionforUnit2areonsiteandplacedin4.3200%S10.731.80649.9000%$123,962,296144000%$3577269storagellaydownareaUnit1SDA-AInletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.1.44000%$3577,269Unit1SDA-CSupportSteelErectionCompleteSteeliserected,plumb,andbolted.1.44000%$3,577,26925Sep-11Unit1SDA-AOutletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.4.0800%$10,135,59553.9800%$134,097,8901.36000%$3,378,532Unit1SDA.AVesselShell/RoofCompleteShellandRoofsetinplace,plumb,andaligned.I.36000%$3,378,532Unit2FabricFilterDeliveryUnit2FabricFilterplenumwallsandhoppersareonsiteandplacedinthe1.36000%$3,378,532storage/laydownarea26Oct-iIUnit2SDAStructuralSteelDeliveryUnit2SDAstructuralsteelisonsiteandplacedinthestorage/laydownarea4.0000%$9,936,85757.9800%$144,034,7472.00000%$4,968,429Unit1SDA-BInletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.2.00000%$4,968,42927Nov-i1Unit1SDA-BVesselShell/RoofCompleteShellandRoofsetinplace,plumb,andaligned.3.9900%S9,912,01561.9700%S153,946,7631.33000%$3,304,005Unit1SDA-BOutletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.1.33000%$3,304,005Unit1FabricFilter-BHoppers/Wall/RoofCompleteFabricFilterHoppersandCompartmentWalls/Roofsareset.plumb,and1.33000%$3,304,005aligned.28Dec-i1nit1SDA-CInletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.3.7000%$9,191.59365.6700%S163,138,3561.85000%$4,595,797nit1SDA-COutletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.1.85000%$4,595,79729Jan-12nit1SDA-CVesselShell/RoofCompleteShellandRoofsetinplace,plumb,andaligned.3.3600%$8,346,96069.0300%$171485,3160.84000%$2,086,740DCSEquipmentDeliveryAllUnit1andUnit2DCSequipmentonsite0.84000%$2,086,740Unit2SDA-AInletDuctSupportSteelCompleteSteeliserected,plumb,andbolted.0.84000%$2,086,740Unit2SDA-ASupportSteelCompleteSteeliserected,plumb,andbolted.0.84000%$2,086,74030Feb-12Unit1BoosterFansErectionCompleteUnit1boosterfans,motors,andlubeoilcoolingsystemequipmentinstalled3.0300%$7,527,16972.0600%S179,012,4851.01000%$2,509,056Unit2SDA-BInletDuctSupportSteelCompleteSteeliserected,plumb,andbolted.1.01000%$2,509,056Unit1FabricFilter-CHoppers/Wall/RoofCompleteFabricFilterHoppersandCompartmentWalls/Roofsareset.plumb,and1.01000%$2,509,056aligned.31Mar-12Unit2SDA-CInletDuctSupportSteelCompleteSteeliserected,plumb,andbolted.2.9400%$7,303,59075.0000%S186,316,0760.98000°$2,434,530Unit2SDA..AVesselShell/RoofCompletehellandRoofsetinplace,plumb,andaligned.0.98000°$2,434,530Unit2SDA-AInletDuctErectionCompleteuctsetonsteel.Alignmentcompletetoextentpossible.0.$2,434,53032Apr-12Unit2SDA-8SupportSteelCompleteeeliserected,plumb,andbolted.3.0600%$7,601,69678.0600%$193,917,771$3,800,848OperatingandMaintenanceManualsPreliminaryreleaseofO&Mmanuals,issuedforOwnerreview1.$3,800,84833May-i2Unit2SDA-BVesselShell/RoofCompleteShellandRoofsetinplace,plumb,andaligned.3.0000%$7,452,64381.0600%$201370,4141.$2484214U!SDA-BInletDuctErectionCompleteDuctsetonsteel,Alignmentcompletetoextentpossible.1.0$2,484,214Urth2SDA-CSupportSteelCompleteSteeliserected,plumb,andbolted,1.0$2,484,21434Jun-12UnitSDA-AOutletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.2.8200%S7,005,48483.8800%S208.375,8991.410$3,502,742UnitFabricFilter-AHoppers/Wall/RoofCompleteFabricFilterHoppersandCompartmentWalls/Roofsareset.plumb,and1.41000%$3,502,742aligned.35Jul-12UnitSDA-CVesselShell/RoofCompleteShellandRoofsetinplace,plumb,andaligned.2.7600%$6,856,43286.6400%$215,232,3301.38000%$3,428,216UnitSDA-CInletDuctErectionCompleteDuctsetonsteel.Alignmentcompletetoextentpossible.I.38000%$3,428.21636Aug-12UnitSDA-BOutietPuctErectiopleteDuctseton2.4000%$5,962,11489.0400%$221,194,4450.80000%$1,987,371UnitFabricFilter-BHoppers5Nali/RoofCompleteFabricFilterHoppersandCompartmentWalls/Roofsareset,ol.imb.and0.80000%$1,987,371ned.Structra2ttorWennobce/SuctualCon’ceonorlJn/38000cSD,.C2.aC.CC—aC—2...2E...a‘—-cc-.-ace’-.38Oct12UntIDuc.tTe-inCompieleSeaiweidwgcompiete.ductreacytoreceivefluegas.2.2300%$5.53979893.5300%5232.348.5672.23000%55.539.79839Nov-12UnitMechanicalCompletionWrittennoticeofMechanicalCompletionforunit104500%S1.117.89693.9800%S233.466.4640.45000%Si.i17.89640Dec-12UnitPerformanceTestReportPerformanceTestReportissuedforOwnerreview0.3000%$745,26494.2800%$234,211.7280.30000%$745,26441Jan13UrntlSubstantialCompletionWrittennoticeoSubstantial02200%$546527945000%$234758255.007400°c=$183832Unit2)tur5lCometlo,,WennoticeQ00%$814tt [OERCRetiremerInformsonUnit41$18i38AttachmentA-i-MilestonePaymentScheduleWhiteBluffUniti&2DFGDProjectCombinedAlstomIZHlPaymentScheduleRev.Date-December11,2009MonthDateMilestone1DescriptionMonthlyInvoiceMonthlyInvoiceCumulativeCumulativeIndividualIndividualCO#1Amount(%>Amount($)3InvoicedInvoicedMilestoneValueMilestoneValueAmount(%)2Amount($)2(%)($)42Feb-13RemovalofFabricationTablesComplete02200%$546,52794.7200%$235,304,7820.22000°!$546,52743Mar-13Unit2DuctTie-InCompleteSealweldingcomplete,ductreadytoreceivefluegas,0.1500%$372,63294.8700%$235,677,4140.15000°!$372,63244Apr-13Unit2MechanicalCompletionWrittennoticeofMechanicalCompletionforUnit20.0700%$173.89594.9400%$235.851,3090.07000°!$173,89545May-13Unit2SubstantialCompletionWrittennoticeofSubstantialCompletionforUnit20.0600%$149,053950000%$236,000,3620.02000°/$49,684DemobilizationCompleteOfficetrailersandconstructionequipmentisremovedfromsite.Fabrication0.02000°!$49,684andlaydownareashavebeenreturnedtopre-mobilizedcondition.FERCRetirementInformation-Unit#20.02000%$49,68452Dec-13Unit1FinalAcceptanceWrittennoticeofFinalAcceptanceforUnit12.5000%$6,210,53697.5000%$242,210,8982.50000%$6,210,53657May-14Unit2FinalAcceptanceWrittennoticeofFinalAcceptanceforUnit22.5000%$6,210,536100.0000%S248,421,4342.50000%$6210,536TOTALS100.0000%$248,421,434100.00000%$248,421,434(5565,2501Notes:1.MilestonesarePreliminaryandsubjecttoadjustmentatsuchtimeastheBaselineScheduleiscompletedandmutuallyagreed.TOTALORIGINALCONTRACTVALUE$248,421,434157%Invoicedtodate$3,900.217TOTALAPPROVEDCHANGEORDERVALUE$(565,250)1.51%Paymenttodate$3,751,164TOTALCURRENTCONTRACTVALUE$247,856,1840.06%OutstandingPayment$149,05398.43%OutstandingtoInvoice$243,955,967

# ATTACHMENT B: SUPPORTING DOCUMENTATION FOR SEMI-DRY SCRUBBING

BOP COSTS

# ATTACHMENT C: SUPPORTING DOCUMENTATION FOR WET SCRUBBING COSTSENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATE SUMMARYPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected Cost1.0ID FANS$ 18,880,700 $ 5,992,200 $ 11,356,500 $ 36,229,4002.0NEW STACK$ - $ - $ - $ 40,924,0003.0LIMESTONE HANDLING SYSTEM$ 7,183,300 $ 3,730,400 $ 9,183,200 $ 20,096,9004.0REAGENT PREPARATION ISLAND$ 15,457,600 $ 5,995,400 $ 14,003,200 $ 35,456,2005.0BYPRODUCT DEWATERING ISLAND$ 9,783,900 $ 6,121,200 $ 12,824,900 $ 28,730,0006.0ABSORBER ISLAND$ 95,571,200 $ 57,537,000 $ 101,468,300 $ 254,576,5007.0FGD WASTE WATER TREATMENT PLANT$ 5,406,000 $ 9,925,900 $ 9,827,600 $ 25,159,5008.0COMPRESSED AIR SYSTEM$ 790,600 $ 200,200 $ 709,600 $ 1,700,4009.0SERVICE WATER SYSTEM$ 977,600 $ 1,486,100 $ 2,468,600 $ 4,932,30010.0POTABLE WATER SYSTEM$ 172,000 $ 134,500 $ 301,900 $ 608,40011.0ELECTRICAL (AUX POWER)$ 1,868,100 $ 192,700 $ 720,500 $ 2,781,30012.0FGD DCS SYSTEM$ 1,030,000 $ 4,606,600 $ 1,929,900 $ 7,566,50013.0ACI SYSTEM$ - $ - $ - $ -14.0RAIL INFRASTRUCTURE$ 226,600 $ 971,000 $ 773,100 $ 1,970,70015.0SITE IMPROVEMENTS - CIVIL WORK$ 416,600 $ 2,898,200 $ 3,591,900 $ 6,906,70016.0BOP ITEMS$ 216,300 $ 1,378,100 $ 1,830,300 $ 3,424,70017.0DEMOLITION$ - $ - $ 410,400 $ 410,400Sargent & Lundy, LLCPage 1 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATE SUMMARYPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC99.0OVERALL - EQUIPMENT, MATERIAL AND LABOR COSTS -PROJECT TOTAL$ 157,980,500 $ 101,169,500 $ 171,399,900 $ 471,473,900OVERALL - OTHER DIRECT & CONSTRUCTION INDIRECT COSTS -PROJECT TOTAL$ 8,826,000 $ 25,798,200 $ 66,452,300 $ 101,076,600OVERALL TOTAL DIRECT & CONSTRUCTION INDIRECT COST -PROJECT TOTAL$ 166,806,500 $ 126,967,700 $ 237,852,200 $ 572,550,500OVERALL PROJECT INDIRECT COSTSENGINEERING, PROCUREMENT, & PROJECT SERVICES$ 28,628,000CONSTRUCTION MANAGEMENT$ 8,588,300S-U / COMMISSIONING$ 5,725,500OWNER'S COST$ 20,039,300SUBTOTAL - INDIRECT COSTS$ 64,649,100TOTAL PROJECT DIRECT AND INDIRECT COSTS$ 637,199,600ESCALATION$ 60,071,000EQUIPMENT$ 12,948,000MATERIAL$ 11,043,000LABOR$ 28,853,000INDIRECTS$ 7,227,000CONTINGENCY$ 139,454,120TOTAL PROJECT COST$ 836,724,720Page 2 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected Cost1.0ID FANS$ 18,880,700 $ 5,992,200 $ 11,356,500 $ 36,229,4001.1ID FANS - OEM EQUIPMENT2,070,000 ACFM WITH 21,500 HPMOTORS ($825,000 EACH. INCLUDESHYDRAULIC OIL UNITS, SEAL AIR FANSKIDS, VIBRATION MONITORINGEQUIPMENT, FAN STALL EQUIPMENT,FIELD SERVICE REP FOR 140 DAYS$ 15,540,000 $ - $ 2,441,600 $ 17,981,6001.2 PIPING & SUPPORTS - MECHANICAL $ 59,700 $ 42,700 $ 139,700 $ 242,1001.3 DAMPERS$ 925,400 $ - $ 303,000 $ 1,228,4001.4 EXPANSION JOINTS$ - $ 165,600 $ 105,900 $ 271,5001.5 DUCTWORK INCLUDES INTERNAL BRACING ANDTURNING VANES$ - $ 2,301,000 $ 3,499,800 $ 5,800,8001.6 DUCT SUPPORT STEEL THREE-COAT SHOP PAINT $ - $ 1,026,600 $ 765,300 $ 1,791,9001.7 ID FAN INSULATION & LAGGING TOTAL FOR TWO FANS. PRICEREFLECTS STANDARD ACOUSTICALINSULATION$ - $ 400,000 $ 335,000 $ 735,0001.8 DUCTWORK INSULATION & LAGGING 0.0 $ - $ 578,200 $ 733,600 $ 1,311,8001.9 SUPPORT STEEL - FOUNDATIONS 0.0 $ - $ 147,300 $ 201,100 $ 348,4001.10 ID FAN PDC / CONTROL ROOM - FOUNDATIONS 0.00 $ - $ 244,100 $ 275,300 $ 519,4001.11 ID FAN PDC / CONTROL ROOM - CONCRETE PIERS 28 PIERS $ - $ 41,400 $ 76,900 $ 118,3001.12 ID FAN - FOUNDATIONS TOTAL FOR TWO FANS $ - $ 458,600 $ 558,100 $ 1,016,7001.13 SWITCHGEAR 0.00 $ 742,600 $ - $ 23,300 $ 765,9001.14 MCC 0.00 $ 129,300 $ - $ 8,200 $ 137,5001.15 ID FAN PDC / CONTROL ROOM 25W X 70' X 13'H $ 901,300 $ - $ 47,300 $ 948,6001.16 138 kV PANELS - RELAY 0.00 $ 103,000 $ - $ 6,600 $ 109,6001.17 2000A, 15KV CABLE BUS & TERMINATIONS 0.00 $ 136,600 $ 7,200 $ 92,100 $ 235,9001.18 MIMIC PANELS 0.00 $ 18,000 $ - $ 4,900 $ 22,9001.19 EMERGENCY POWER SYSTEM 0.00 $ 294,100 $ - $ 28,300 $ 322,4001.20 GROUNDING 0.00 $ 3,900 $ - $ 10,800 $ 14,7001.21 LIGHTING/ TRANSFORMERS & PANELS $ 26,800 $ 30,000 $ 21,300 $ 78,1001.22 RACEWAY, CABLE TRAY, & CONDUIT $ - $ 390,600 $ 1,386,800 $ 1,777,4001.23 HIGH VOLTAGE POWER CABLE & TERMINATION 1/C # 500KCMIL-15KV $ - $ 12,500 $ 25,500 $ 38,0001.24 LOW VOLTAGE POWER CABLE & TERMINATION 0.00 $ - $ - $ 81,100 $ 81,1001.25 CONTROL & INSTRUMENT CABLE #14, #16 & PR # 20 & SHLD WIRE $ - $ 41,000 $ 83,100 $ 124,1001.26 DUCT BANK 37"H X 62.5"W (75'+150'=225') $ - $ 73,400 $ 83,000 $ 156,4001.27 COMMUNICATIONS$ - $ 17,000 $ 9,400 $ 26,400Sargent & Lundy, LLCPage 3 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC1.28LIGHTNING PROTECTION$ - $ 7,000 $ 4,400 $ 11,4001.29SECURITY SYSTEM$ - $ 8,000 $ 5,100 $ 13,1002.0NEW STACK$ - $ - $ - $ 40,924,0002.1CONCRETE STACK (WET - FRP LINED)0.0$ - $ - $ - $ 40,924,0003.0LIMESTONE HANDLING SYSTEM$ 7,183,300 $ 3,730,400 $ 9,183,200 $ 20,096,9003.1MATERIAL HANDLING EQUIPMENT$ 4,908,200 $ 845,000 $ 2,567,600 $ 8,320,8003.2FIRE PROTECTION SYSTEM FOR BELT CONVEYORSDELUGE SYSTEM, DRY PIPE,SENSORS, ACTIVATION VALVE ANDFM APPROVED PANEL -SUBCONTRACT PRICE FOR ALLCONVEYORS INCLUDES LABOR$ 679,800 $ - $ - $ 679,8003.3PIPING - MECHANICAL$ 4,900 $ 1,700 $ 9,600 $ 16,2003.4CONVEYOR STRUCTURE SUPPORT STEELTHREE-COAT SHOP PAINT $ - $ 290,000 $ 216,200 $ 506,2003.5CONVEYOR SUPPORT STEEL - FOUNDATIONS$ - $ 16,000 $ 34,000 $ 50,0003.6RAILCAR LIMESTONE UNLOADING HOPPER, CONVEYOR TUNNELAND ESCAPE TUNNEL - FOUNDATIONS$ - $ 542,000 $ 1,086,800 $ 1,628,8003.7LIMESTONE TRANSFER TOWER - FOUNDATIONS$ - $ 15,400 $ 20,600 $ 36,0003.8LIMESTONE TRANSFER CONVEYOR - FOUNDATIONS$ - $ 62,000 $ 85,800 $ 147,8003.9LIMESTONE RECLAIM HOPPER, CONVEYOR TUNNEL ANDESCAPE TUNNEL - FOUNDATIONS$ - $ 542,000 $ 1,086,800 $ 1,628,8003.10LIMESTONE UNLOADING PDC - FOUNDATIONS$ - $ 24,500 $ 30,700 $ 55,2003.11LIMESTONE UNLOADING PDC - CONCRETE PIERS10 PIERS$ - $ 6,900 $ 12,800 $ 19,7003.12LIMESTONE RECLAIM PDC - FOUNDATIONS$ - $ 16,800 $ 21,700 $ 38,5003.13LIMESTONE RECLAIM PDC - CONCRETE PIERS10 PIERS$ - $ 6,900 $ 12,800 $ 19,7003.14TRANSFORMERSLIMESTONE UNLOADING & RECLAIMAREAS$ 175,100 $ - $ 40,800 $ 215,900Page 4 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC3.15SWITCHGEARLIMESTONE UNLOADING & RECLAIMAREAS$ 161,500 $ - $ 9,300 $ 170,8003.16LIMESTONE UNLOADING PDC18W X 50' X 10'H$ 463,500 $ - $ 24,300 $ 487,8003.17LIMESTONE RECLAIM PDC15W X 30' X 10'H$ 231,800 $ - $ 12,200 $ 244,0003.18MCCLIMESTONE UNLOADING & RECLAIMAREAS$ 127,400 $ - $ 5,200 $ 132,6003.19CABLE BUS DUCTLIMESTONE UNLOADING & RECLAIMAREAS$ 138,700 $ 5,400 $ 135,800 $ 279,9003.20MIMIC PANELS$ 18,000 $ - $ 3,300 $ 21,3003.21EMERGENCY POWER SYSTEMLIMESTONE UNLOADING & RECLAIMAREAS$ 222,800 $ - $ 35,500 $ 258,3003.22LIGHTING/ TRANSFORMERS & PANELS$ 26,800 $ 67,500 $ 37,800 $ 132,1003.23GROUNDINGLIMESTONE UNLOADING & RECLAIMAREAS$ 24,800 $ - $ 45,000 $ 69,8003.24RACEWAY, CABLE TRAY, & CONDUIT$ - $ 801,100 $ 2,600,300 $ 3,401,4003.25HIGH VOLTAGE POWER CABLE & TERMINATION1/C # 500KCMIL-15KV$ - $ 33,400 $ 68,000 $ 101,4003.26LOW VOLTAGE POWER CABLE & TERMINATION0.00$ - $ 130,600 $ 517,100 $ 647,700Page 5 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC3.27CONTROL & INSTRUMENT CABLE#14, #16 & PR # 20 & SHLD WIRE $ - $ 140,800 $ 285,600 $ 426,4003.28DUCT BANKDUCT BANK WITH 12-5" CONDUIT,37"H X 62.5"W (325'+50'=375')$ - $ 122,400 $ 138,400 $ 260,8003.29FOUNDATIONS FOR TRANSFORMERSLIMESTONE UNLOADING & RECLAIMAREAS$ - $ 3,500 $ 6,400 $ 9,9003.30COMMUNICATIONS$ - $ 34,000 $ 18,800 $ 52,8003.31LIGHTNING PROTECTION$ - $ 6,500 $ 3,900 $ 10,4003.32SECURITY SYSTEM$ - $ 16,000 $ 10,100 $ 26,1004.0REAGENT PREPARATION ISLAND$ 15,457,600 $ 5,995,400 $ 14,003,200 $ 35,456,2004.1MECHANICAL EQUIPMENTINCLUDES LIMESTONE FEEDERS,FROM THE SILOS THROUGH THESLURRY STORAGE TANKS ANDTRANSFER PUMPS WITH INTEGRALPIPING$ 14,709,700 $ - $ 9,306,900 $ 24,016,6004.2REAGENT PREPARATION BUILDING SUMP PUMPSDUPLEX. INCLUDES CHECK &ISOLATION VALVES$ 28,800 $ - $ 8,800 $ 37,6004.3AGITATOR FOR SUMP PUMPS5 HP$ 12,400 $ - $ 3,300 $ 15,7004.4PIPING - MECHANICAL$ 373,500 $ 279,600 $ 588,800 $ 1,241,9004.5LIMESTONE SLURRY TANKS - FOUNDATIONS$ - $ 166,400 $ 202,200 $ 368,6004.6REAGENT PREPARATION BUILDING - FOUNDATIONS$ - $ 649,100 $ 717,200 $ 1,366,3004.7REAGENT PREPARATION BUILDING120' L X 125' W X 130' H$ 277,500 $ 4,686,500 $ 3,040,900 $ 8,004,9004.8PIPE SUPPORT PAD - REAGENT PREP BUILDING$ - $ 13,800 $ 18,100 $ 31,9004.9LIGHTING/ TRANSFORMERS & PANELS$ 53,600 $ 135,000 $ 75,700 $ 264,3004.10GROUNDING$ 2,100 $ - $ 5,800 $ 7,9004.11RACEWAY, CABLE TRAY, & CONDUITINCLUDED IN ABSORBER ISLAND,SECTION 7.0$ - $ - $ - $ -4.12COMMUNICATIONS$ - $ 34,000 $ 18,800 $ 52,8004.13LIGHTNING PROTECTION$ - $ 23,000 $ 11,600 $ 34,6004.14SECURITY SYSTEM$ - $ 8,000 $ 5,100 $ 13,100Page 6 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC5.0BYPRODUCT DEWATERING ISLAND$ 9,783,900 $ 6,121,200 $ 12,824,900 $ 28,730,0005.1MECHANICAL EQUIPMENTPRIMARY & SECONDARY$ 7,323,300 $ - $ 4,630,200 $ 11,953,5005.2PIPING - MECHANICAL$ 378,500 $ 1,626,500 $ 2,579,300 $ 4,584,3005.3MATERIAL HANDLING EQUIPMENT$ 745,900 $ 5,000 $ 435,000 $ 1,185,9005.4FIRE PROTECTION SYSTEM FOR BELT CONVEYORSDELUGE SYSTEM, DRY PIPE,SENSORS, ACTIVATION VALVE ANDFM APPROVED PANEL$ 175,100 $ - $ - $ 175,1005.5 BYPRODUCT DEWATERING BUILDING SUMP PUMPS &AGITATORS$ 41,200 $ - $ 12,100 $ 53,3005.6CONVEYOR STRUCTURE SUPPORT STEELTHREE-COAT SHOP PAINT $ - $ 99,000 $ 73,800 $ 172,8005.7BYPRODUCT STACKOUT CONVEYOR - FOUNDATIONS$ - $ 30,100 $ 44,100 $ 74,2005.8BYPRODUCT STACKOUT PILE - FOUNDATIONSINCLUDES CONTAINMENT AREA $ - $ 1,155,700 $ 1,243,500 $ 2,399,2005.9BYPRODUCT CONTAINMENT WALLS$ - $ 137,300 $ 156,700 $ 294,0005.10INSTALL WIND SCREEN$ - $ 525,000 $ 119,700 $ 644,7005.11BYPRODUCT DEWATERING BUILDING - FOUNDATIONS$ - $ 275,400 $ 304,600 $ 580,0005.12BYPRODUCT DEWATERING BUILDING120' L X 71' W X 65' H$ 149,600 $ 1,536,800 $ 1,062,100 $ 2,748,5005.13PIPE SUPPORT PAD$ - $ 13,800 $ 17,900 $ 31,7005.14TRANSFORMERS$ 175,100 $ - $ 35,000 $ 210,1005.15SWITCHGEAR480V LOW VOLATAGE SWITCHGEAR, $ 201,900 $ - $ 67,100 $ 269,0005.16CABLE BUS DUCT$ 277,500 $ 10,800 $ 271,600 $ 559,9005.17MCC$ 127,300 $ - $ 4,600 $ 131,9005.18MIMIC PANELS$ 18,000 $ - $ 1,100 $ 19,1005.19EMERGENCY POWER SYSTEM$ 111,300 $ - $ 17,800 $ 129,1005.20GROUNDING$ 5,600 $ - $ 13,500 $ 19,1005.21LIGHTING/ TRANSFORMERS & PANELS$ 53,600 $ 135,000 $ 75,700 $ 264,3005.22RACEWAY, CABLE TRAY, & CONDUIT$ - $ 326,100 $ 1,007,300 $ 1,333,4005.23HIGH VOLTAGE POWER CABLE & TERMINATION1/C # 500KCMIL-15KV$ - $ 13,900 $ 28,300 $ 42,2005.24LOW VOLTAGE POWER CABLE & TERMINATION0.00$ - $ 73,100 $ 385,900 $ 459,0005.25CONTROL & INSTRUMENT CABLE#14, #16 & PR # 20 & SHLD WIRE $ - $ 99,200 $ 201,200 $ 300,4005.26FOUNDATIONS FOR TRANSFORMERS$ - $ 3,500 $ 6,400 $ 9,9005.27COMMUNICATIONS$ - $ 34,000 $ 18,800 $ 52,8005.28LIGHTNING PROTECTION$ - $ 13,000 $ 6,500 $ 19,500Page 7 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC5.29SECURITY SYSTEM$ - $ 8,000 $ 5,100 $ 13,1006.0ABSORBER ISLAND$ 95,571,200 $ 57,537,000 $ 101,468,300 $ 254,576,5006.1MECHANICAL EQUIPMENTINCLUDES ABSORBER MODULE $ 83,613,300 $ - $ 58,172,100 $ 141,785,4006.2ADDITIONAL COST FOR C276 ABSORBER SHELL MATERIALABOVE THE PRICE OF A2205 ABSORBER SHELLINCLUDES MATERIAL AND WELDINGROD COST DIFFERENTIAL49,800 TOTAL SF$ - $ 30,676,800 $ - $ 30,676,8006.3ABSORBER BUILDING SUMP PUMPSDUPLEX. INCLUDES CHECK & $ 57,700 $ - $ 17,700 $ 75,4006.4AGITATOR FOR SUMP PUMPS5 HP$ 24,700 $ - $ 6,600 $ 31,3006.5EMERGENCY DIESEL DRIVEN QUENCH PUMPWITH FUEL DAY TANK.FOUNDATIONS INCLUDED WITH$ 309,000 $ - $ 44,100 $ 353,1006.6PIPING - MECHANICALALL PIPING INCLUDED IN OEM $ - $ - $ - $ -6.7ABSORBER VESSEL - FOUNDATIONS$ - $ 733,900 $ 893,700 $ 1,627,6006.8ABSORBER BUILDING - FOUNDATIONS$ - $ 1,088,600 $ 1,200,000 $ 2,288,6006.9ABSORBER BUILDING150' L X 85' W X 60' H$ 338,900 $ 4,971,200 $ 3,796,000 $ 9,106,1006.10PIPE SUPPORT PAD - ABSORBER BUILDING$ - $ 15,400 $ 21,800 $ 37,2006.11OXIDATION AIR BLOWER BUILDING - FOUNDATIONS$ - $ 73,800 $ 90,400 $ 164,2006.12OXIDATION AIR BLOWER BUILDING30' L X 30' W X 25' H$ 69,600 $ 347,700 $ 310,800 $ 728,1006.13PIPE SUPPORT PAD - OXIDATION BUILDING$ - $ 15,400 $ 18,800 $ 34,2006.14DUCTWORKINCLUDES INTERNAL BRACING AND $ - $ 7,117,500 $ 10,825,800 $ 17,943,3006.15DUCT SUPPORT STEELTHREE-COAT SHOP PAINT $ - $ 3,172,600 $ 2,365,100 $ 5,537,7006.16DUCTWORK INSULATION & LAGGING$ - $ 2,522,400 $ 3,200,500 $ 5,722,9006.17FOUNDATIONS FOR DUCT SUPPORT STEEL$ - $ 137,800 $ 189,800 $ 327,6006.18TRANSFORMERS$ 2,432,900 $ - $ 338,300 $ 2,771,2006.19SWITCHGEAR$ 3,787,100 $ - $ 1,433,400 $ 5,220,5006.20CABLE BUS & TERMINATIONS$ 3,416,100 $ 93,100 $ 4,311,600 $ 7,820,8006.21MCC$ 891,200 $ - $ 32,000 $ 923,2006.22MIMIC PANELS$ 36,100 $ - $ 5,700 $ 41,8006.23GROUNDING$ 32,900 $ - $ 66,600 $ 99,5006.24LIGHTING/ TRANSFORMERS & PANELS$ 338,900 $ 330,000 $ 247,700 $ 916,6006.25EMERGENCY POWER SYSTEM$ 222,800 $ - $ 35,500 $ 258,3006.26RACEWAY, CABLE TRAY, & CONDUIT$ - $ 3,031,300 $ 8,438,900 $ 11,470,2006.27HIGH VOLTAGE POWER CABLE & TERMINATION$ - $ 116,800 $ 238,100 $ 354,900Page 8 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC6.28MEDIUM VOLTAGE POWER CABLE & TERMINATION$ - $ 229,100 $ 624,100 $ 853,2006.29LOW VOLTAGE POWER CABLE & TERMINATION$ - $ 1,591,700 $ 2,169,300 $ 3,761,0006.30CONTROL & INSTRUMENT CABLE$ - $ 1,024,000 $ 2,076,900 $ 3,100,9006.31FOUNDATION FOR TRANSFORMERS$ - $ 118,000 $ 216,200 $ 334,2006.32TRANSFORMER FIRE WALLS$ - $ 6,900 $ 12,000 $ 18,9006.33COMMUNICATIONS$ - $ 68,000 $ 37,600 $ 105,6006.34LIGHTNING PROTECTION$ - $ 39,000 $ 21,000 $ 60,0006.35SECURITY SYSTEM$ - $ 16,000 $ 10,200 $ 26,2007.0FGD WASTE WATER TREATMENT PLANT$ 5,406,000 $ 9,925,900 $ 9,827,600 $ 25,159,5007.1WWT MECHANICAL EQUIPMENT:$ 4,635,000 $ - $ 772,200 $ 5,407,2007.2PIPING - MECHANICAL$ 96,400 $ 562,300 $ 1,283,200 $ 1,941,9007.3PUMPS$ 119,500 $ 58,500 $ 97,000 $ 275,0007.4TANKS$ - $ 4,770,000 $ 1,086,900 $ 5,856,9007.5PRIMARY CLARIFIER - FOUNDATIONS$ - $ 46,900 $ 74,600 $ 121,5007.6SECONDARY CLARIFIER - FOUNDATIONS$ - $ 46,900 $ 74,600 $ 121,5007.7RECLAIM WATER TANKS - FOUNDATIONSTOTAL FOR TWO TANKS$ - $ 51,900 $ 72,100 $ 124,0007.8EQUALIZATION TANKS - FOUNDATIONSTOTAL FOR TWO TANKS$ - $ 10,900 $ 17,300 $ 28,2007.9MAINTENANCE STORAGE TANK - FOUNDATIONS$ - $ 199,900 $ 236,300 $ 436,2007.10WWT BUILDING - FOUNDATIONS$ - $ 603,900 $ 704,500 $ 1,308,4007.11WWT BUILDING125' L X 90' W X 25' H$ 86,500 $ 1,737,800 $ 1,352,000 $ 3,176,3007.12PIPE SUPPORT PAD$ - $ 27,600 $ 36,400 $ 64,0007.13MCC$ 127,300 $ - $ 5,300 $ 132,6007.14EMERGENCY POWER SYSTEM$ 222,800 $ - $ 35,500 $ 258,3007.15GROUNDING$ 11,400 $ - $ 27,000 $ 38,4007.16LIGHTING / TRANSFORMERS & PANELS$ 107,100 $ 120,000 $ 85,400 $ 312,5007.17RACEWAY, CABLE TRAY, & CONDUIT$ - $ 1,072,500 $ 3,120,600 $ 4,193,1007.18LOW VOLTAGE POWER CABLE & TERMINATION$ - $ 500,800 $ 681,500 $ 562,1007.19CONTROL & INSTRUMENT CABLE#14, #16 & PR # 20 & SHLD WIRE $ - $ 204,800 $ 415,400 $ 620,2007.20COMMUNICATIONS$ - $ 68,000 $ 37,600 $ 105,6007.21LIGHTNING PROTECTION$ - $ 32,000 $ 17,400 $ 49,4007.22SECURITY SYSTEM$ - $ 16,000 $ 10,200 $ 26,2008.0COMPRESSED AIR SYSTEM$ 790,600 $ 200,200 $ 709,600 $ 1,700,400Page 9 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC8.1AIR COMPRESSOR & AUXILIARIES3000 CFM$ 411,000 $ - $ 80,900 $ 491,9008.2PIPING - MECHANICAL$ 379,600 $ 200,200 $ 628,700 $ 1,208,5008.3ELECTRICALINCLUDED IN REAGENTPREPARATION, SECTION 5.0$ - $ - $ - $ -9.0SERVICE WATER SYSTEM$ 977,600 $ 1,486,100 $ 2,468,600 $ 4,932,3009.1PUMPSINCLUDES SELF-CLEANINGSTRAINERS$ 210,100 $ - $ 64,800 $ 274,9009.2PIPING - MECHANICAL$ 493,200 $ 1,205,400 $ 1,988,800 $ 3,687,4009.3PIPING - FIRE PROTECTION SYSTEM$ 274,300 $ 143,400 $ 387,100 $ 804,8009.4TANKS$ - $ 120,000 $ - $ 120,0009.5SERVICE WATER TANK & PUMP - FOUNDATIONS$ - $ 17,300 $ 27,900 $ 45,2009.6ELECTRICALINCLUDED IN REAGENTPREPARATION, SECTION 5.0$ - $ - $ - $ -10.0POTABLE WATER SYSTEM$ 172,000 $ 134,500 $ 301,900 $ 608,40010.1PUMPS$ 30,900 $ - $ 13,200 $ 44,10010.2PIPING - MECHANICAL$ 141,100 $ 120,800 $ 282,300 $ 544,20010.3TANKS$ - $ 8,500 $ - $ 8,50010.4POTABLE WATER TANK & PUMP - FOUNDATIONS$ - $ 5,200 $ 6,400 $ 11,60010.5ELECTRICALINCLUDED IN REAGENTPREPARATION, SECTION 5.0$ - $ - $ - $ -11.0ELECTRICAL (AUX POWER)$ 1,868,100 $ 192,700 $ 720,500 $ 2,781,30011.1138/13.8 KV STATION SERVICE TRANSFORMERS$ 1,432,200 $ - $ 140,000 $ 1,572,20011.2138KV MAIN FEEDER & TERMINATIONS$ 271,800 $ - $ 184,500 $ 456,30011.3SWITCHGEAR$ 127,900 $ - $ 61,600 $ 189,50011.4DUCTBANKS$ - $ 108,200 $ 100,500 $ 208,70011.5GROUNDING$ 10,400 $ - $ 19,400 $ 29,80011.6OUTDOOR LIGHTING$ 25,800 $ - $ 41,100 $ 66,90011.7FOUNDATION FOR AUX TRANSFORMER$ - $ 63,200 $ 133,800 $ 197,00011.8FIRE WALL FOR AUX TRANSFORMER$ - $ 21,300 $ 39,600 $ 60,90012.0FGD DCS SYSTEM$ 1,030,000 $ 4,606,600 $ 1,929,900 $ 7,566,50012.1DCS5000 I/O POINTS$ - $ 3,750,000 $ 906,500 $ 4,656,50012.2DCS - VENDOR FIELD SUPPORT200 MANDAYS @ $1500/DAY - SHOWN $ 309,000 $ - $ - $ 309,000Page 10 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC12.3LOCALLY MOUNTED INSTRUMENTS$ - $ 856,600 $ 907,400 $ 1,764,00013.0ACI SYSTEM$ - $ - $ - $ -13.1CONCRETE$ - $ - $ - $ -13.2STEEL$ - $ - $ - $ -13.3ARCHITECTURAL$ - $ - $ -13.4MECHANICAL EQUIPMENT$ - $ - $ -13.5PIPING$ - $ - $ -13.6ELECTRICAL EQUIPMENT$ - $ - $ -13.7RACEWAY, CABLE TRAY, & CONDUIT$ - $ - $ -13.8CABLE$ - $ - $ - $ -14.0RAIL INFRASTRUCTURE$ 226,600 $ 971,000 $ 773,100 $ 1,970,70014.1ENCLOSED RAILCAR UNLOADING SHED INCL DUST COLLECTION 0.0$ - $ 220,000 $ 243,200 $ 463,20014.2NEW TRACKS0.0$ - $ 621,000 $ 419,300 $ 1,040,30014.3REALIGN AND RESURFACE TRACKS0.0$ - $ 130,000 $ 110,600 $ 240,60014.4TRACKMOBILE0.0$ 226,600 $ - $ - $ 226,60015.0SITE IMPROVEMENTS - CIVIL WORK$ 416,600 $ 2,898,200 $ 3,591,900 $ 6,906,70015.1SITE GRADING$ - $ - $ 404,400 $ 404,40015.2ROADS & SURFACING$ - $ 605,100 $ 524,900 $ 1,130,00015.3LIMESTONE HANDLING & STORAGE$ - $ 340,100 $ 420,900 $ 761,00015.4GYPSUM HANDLING & STORAGE$ - $ 1,147,200 $ 1,110,300 $ 2,257,50015.5GYPSUM RUNOFF POND$ 61,800 $ 110,400 $ 202,000 $ 374,20015.6BYPRODUCT POND PUMP STRUCTURE - CONCRETE$ - $ 47,000 $ 75,600 $ 122,60015.7STORMWATER DRAINAGE TRENCH2' W X 3' DEEP CAST-IN-PLACE $ - $ 472,500 $ 299,200 $ 771,70015.8STORMWATER RUNOFF POND$ - $ 15,000 $ 89,500 $ 104,50015.9STORM WATER POND PUMP STRUCTURE - CONCRETE$ 92,700 $ 42,300 $ 131,100 $ 266,10015.10 OILY WATER SEWER$ 4,600 $ 80,600 $ 134,000 $ 219,20015.11 OIL SEPARATOR500 GPM W/ INTEGRAL LIFT STATION $ 103,000 $ - $ 83,600 $ 186,60015.12 SANITARY SEWER$ - $ 22,200 $ 69,800 $ 92,00015.13 SANITARY LIFT STATIONPACKAGED TYPE COMPLETE WITH $ 154,500 $ - $ 35,400 $ 189,90015.14 EROSION & SEDIMENT CONTROL$ - $ 15,800 $ 11,200 $ 27,000Page 11 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLC16.0BOP ITEMS$ 216,300 $ 1,378,100 $ 1,830,300 $ 3,424,70016.1PIPE INSULATIONAVERAGE 6" PIPE SIZE$ - $ 78,000 $ 135,800 $ 213,80016.2HEAT TRACING$ - $ 332,700 $ 343,100 $ 675,80016.3TOUCH UP PAINT (INCLUDES PAINTING CS PIPE)$ - $ 181,900 $ 459,000 $ 640,90016.4HOISTS & TROLLEYS$ 185,400 $ 210,000 $ 176,500 $ 571,90016.5MISC AUX STEEL FOR PIPE SUPPORTSFIELD FABRICATED$ - $ 140,000 $ 432,400 $ 572,40016.6MISC PIPE SUPPORT FOUNDATIONS$ - $ 10,500 $ 14,300 $ 24,80016.7EYE WASH STATIONS$ 30,900 $ 5,000 $ 22,100 $ 58,00016.8FIRE PROTECTION FOR MISC BUILDINGS & AREAS$ - $ 420,000 $ 247,100 $ 667,10017.0DEMOLITION$ - $ - $ 410,400 $ 410,40017.1MISCELLANEOUS DEMOLISHING COSTS$ - $ - $ 410,400 $ 410,40099.0OVERALL - EQUIPMENT, MATERIAL AND LABOR COSTS -PROJECT TOTAL$ 157,980,500 $ 101,169,500 $ 171,399,900 $ 471,473,900OVERALL - OTHER DIRECT & CONSTRUCTION INDIRECT COSTS -PROJECT TOTAL$ 8,826,000 $ 25,798,200 $ 66,452,300 $ 101,076,600OVERALL TOTAL DIRECT & CONSTRUCTION INDIRECT COST -PROJECT TOTAL$ 166,806,500 $ 126,967,700 $ 237,852,200 $ 572,550,500OVERALL PROJECT INDIRECT COSTSENGINEERING, PROCUREMENT, & PROJECT SERVICES$ 28,628,000CONSTRUCTION MANAGEMENT$ 8,588,300S-U / COMMISSIONING$ 5,725,500OWNER'S COST$ 20,039,300SUBTOTAL - INDIRECT COSTS$ 64,649,100TOTAL PROJECT DIRECT AND INDIRECT COSTS$ 637,199,600ESCALATION$ 60,071,000EQUIPMENT$ 12,948,000Page 12 of 13ENTERGYEstimate No.:31946AWHITE BLUFF STATION UNIT 1 & 2Project No.:12721-000WET FGD - 2.0 LB/MMBTUDate:11/30/2012ORDER OF MAGNITUDE COSTESTIMATEPreparer:AKReviewer:FSApprover:MNOAccount No.Item DescriptionScope DefinitionTotal Equipment Cost Total Material Cost Total Construction &Erection CostTotal Projected CostSargent & Lundy, LLCMATERIAL$ 11,043,000LABOR$ 28,853,000INDIRECTS$ 7,227,000CONTINGENCY$ 139,454,120TOTAL PROJECT COST$ 836,724,720Page 13 of 13

# ATTACHMENT D: 2008 S&L WET VS. DRY FGD STUDY

# W HITE 

# B LUFF 

# S TATION 

# U NITS 

# 1 AND 

# 2

E VALUATION OF 

# W ET VS



# . D RY 

# FGD T ECHNOLOGIES

SL-009510

Rev. 3

October 28, 2008

Project 12303-004

Prepared by

55 East Monroe Street • Ch icago, IL 60603 USA • 312-269-2000

## LEGAL NOTICE

This report was prepared by Sargent & Lundy, L.L.C., hereinafte r referred to as S&L, expressly for Entergy Arkansas, Inc.,

hereinafter referred to as Entergy. Neither S&L nor any person acting on its behalf (a) makes an y warranty, express or implied,

with respect to the use of any information or methods disclosed in this report or (b) assumes any liability with respect to the

use of any information or methods disclosed in this report.

## W HITE 

## B LUFF 

## S TATION 

## U NITS 

## 1 AND 

## 2 SL-009510

E VALUATION OF 

## W ET VS



## . D RY 

## FGD T ECHNOLOGIES

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued

10-28-08

Project 12303-004 

# CONTRIBUTORS

P REPARED BY 

## :

W. A Patel K. S Aita

Processes Processes

R EVIEWED BY 

## :

S. M. Katzberger

Processes

A PPROVED BY 

## :

C. A. Radek Date

Project Manager

## i

W HITE 

## B LUFF 

## S TATION 

## U NITS 

## 1 AND 

## 2 SL-009510

E VALUATION OF 

## W ET VS



## . D RY 

## FGD T ECHNOLOGIES



# CONTENTS

Section Page

EntergyArkansas WB1-2_Dry vs Wet FGD Study Rev 3 Issued

10-28-08

Project 12303-004 

# 1. I NTRODUCTION



# ............................................................................................................................... ....1-1

1.1 P URPOSE



## ............................................................................................................................... ......................... 1-1

1.2 S TUDY 

## A PPROACH



## ............................................................................................................................... .......... 1-1

1.3 S TUDY 

## B ASIS



## ............................................................................................................................... .................. 1-2

1.3.1 Unit Design .................................................................................................................... ....................... 1-2

1.3.2 Economic Information........................................................................................................... ................ 1-3

1.3.3 Fuel Information............................................................................................................... ..................... 1-4



# 2. S ULFUR 

# R EDUCTION 

# T ECHNOLOGY 

# E VALUATIONS 

# ..........................................................................2-1

2.1 P URPOSE



## ............................................................................................................................... ......................... 2-1

2.2 T ECHNOLOGY 

## D ESCRIPTIONS 

## ........................................................................................................................ 2-1

2.2.1 Lime Spray Dry FGD (LSD FGD)................................................................................................... ..... 2-2

2.2.2 Wet Limestone FGD with Forced Oxidation (LSFO FGD)................................................................ 2-11



# 3. C OMPARISON OF 

# LSD AND 

# LSFO FGD P ROCESSES 

# .........................................................................3-1

3.1 D ESIGN 

## B ASIS



## ............................................................................................................................... ................. 3-1

3.2 G ENERAL 

## A RRANGEMENT 

## ............................................................................................................................. 3- 3

3.2.1 Lime Spray Dryer (LSD) FGD..................................................................................................... ......... 3-3

3.2.2 Wet FGD ........................................................................................................................ ....................... 3-3

3.3 C OMPARISON OF 

## S YSTEM 

## F EATURES 

## ............................................................................................................ 3-4

3.3.1 Absorber Vessel ................................................................................................................ .................... 3-4

3.3.2 Chimney ........................................................................................................................ ........................ 3-5

3.3.3 Chemistry ...................................................................................................................... ........................ 3-5

3.3.4 Chloride Blowdown .............................................................................................................. ................ 3-6

3.3.5 Water Consumption.............................................................................................................. ................. 3-6

3.3.6 SO 2 

## Control ....................................................................................................................... .................... 3-6

3.3.7 Particulate Control ............................................................................................................ .................... 3-7

3.3.8 SO 3 

## Removal....................................................................................................................... .................. 3-8

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# CONTENTS

Section Page

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## 3.3.9 Mercury Collection ............................................................................................................. .................. 3-8

3.3.10 Preliminary CO 2 

## Considerations for Dry and Wet FGD....................................................................... 3-9

3.4 C OMPARISON OF 

## C ONSUMABLES AND 

## W ASTES 

## .......................................................................................... 3-10

3.4.1 Power Consumption .............................................................................................................. .............. 3-10

3.4.2 Reagent Consumption ............................................................................................................ ............. 3-11

3.4.3 Waste Byproducts ............................................................................................................... ................ 3-11

3.5 S ULFUR 

## R EDUCTION 

## T ECHNOLOGY 

## C OST 

## E VALUATION 

## ............................................................................ 3-12

3.5.1 Capital Cost................................................................................................................... ...................... 3-12

3.5.2 Fixed and Variable Operating Costs ............................................................................................. ...... 3-15

3.5.3 Preliminary Cost Summary ....................................................................................................... .......... 3-17

3.5.4 Sensitivity Analyses........................................................................................................... ................. 3-18

3.6 S ULFUR 

## R EDUCTION 

## T ECHNOLOGY 

## C ONCLUSIONS 

## .................................................................................... 3-24

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# FIGURES AND TABLES

No. Page

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## Table 1-1. Major Economic Parameters........................................................................................... ...........................................1-3

Table 2-1. FGD System Deployment in U.S........................................................................................ .......................................2-1

Table 3-1. Design Basis Used for Dry FGD vs. Wet FGD. Comparison............................................................... .....................3-1

Table 3-2. Typical PRB Coal SO 2 

## Emissions Expected from FGD Technology........................................................................3-7

Table 3-3. FGD System Labor Requirements ....................................................................................... ....................................3-15

Table 3-4. O&M Cost Basi s (both units combined)................................................................................ ..................................3-16

Table 3-5. Summary Comparison of Wet and Dry FGD Leveli zed Costs (yr. 2013) for White Bluff Units 1 & 2..................3-17

Figure 2-1. Relationship Between SO 2 

## to Dry FGD and SO 2 

## Reduction Efficiency ..................................................................2-3

Figure 2-2. Typical Dry FGD System............................................................................................. ............................................2-4

Figure 2-3. Typical SDA (B&W).................................................................................................. ..............................................2-8

Figure 2-4. Typical Puls e Jet Fabric Filter .................................................................................... ............................................2-10

Figure 2-5. Typical Wet Limestone FGD System................................................................................... ..................................2-15

Figure 2-6. Typical Ball M ill for Large FGD System............................................................................. ..................................2-16

Figure 2-7. Typical FGD Scrubber with Absorption Tray.......................................................................... ..............................2-18

Figure 2-8. FGD Scrubber with Open-Spray Tower................................................................................. ................................2-19

Figure 2-9. Typical Vacuum Be lt Filte r ......................................................................................... ...........................................2-22

Figure 2-10. Typical Rotary Drum Vacuum Filter................................................................................. ...................................2-23

Figure 3-1. Impact of SO 2 

## in Fuel on Le velized Cost ..................................................................................................... ..........3-19

Figure 3-2. Impact of Rail Delivery on Leve lized Cost .......................................................................... ..................................3-20

Figure 3-3. Impact of Two Dry FGD Absorber Modules on Levelized Cost ........................................................... ................3-21

Figure 3-4. Impact of Mercury Control with ACI for Future Hg-M ACT on Levelized Cost ............................................ .......3-22

Figure 3-5. Impact of Mercury Control with ACI Ahead of COHPAC Baghouse for Wet FGD to Met Future Hg-MACT ...3-23

Figure 3-6. Impact of SO 3 

## Control with Trona Injection for Future SCR Re sulting in Increased Sulfuric Acid Emission......3-24

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# APPENDIXES

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## A. Dry FGD General Arrangement

B. Wet FGD General Arrangement

C. Dry FGD Capital Cost Estimate

D. Wet FGD Capital Cost Estimate

E. Financial Analysis Summary

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# 1. INTRODUCTION

1.1 PURPOSE

The purpose of the study was to select the flue gas desu lfurization (FGD) process best suited for application at

Entergy’s White Bluff Station Units 1 and 2. The most commonly used wet and dry FGD processes were evaluated

relative to one another using a structured methodology to achieve that goal. The study developed conceptual

designs, order of magnitude cost estimates, and economic analyses of adding wet or dry FGD systems.



# 1.2 STUDY APPROACH

The initial task for the study was to evaluate emission control technologies that might be applied to reduce SO X



## emissions from Entergy’s White Bluff Station. The most commonly used wet and dry technologies were identified

as potential solutions for SO X 

## control for these units based on current configurations. The following is a list of the

major activities that were performed in the conceptual design of the t echnologies described in this report.

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## • Material balances and process flow diagrams were developed to identify how the White Bluff units

currently operate and how the addition of SO X 

## control technologies would change their operation.

• Based on the material balances that were develope d, preliminary sizing of various emission control

technology equipment was done for SO X 

## control technologies as well as balance-of-plant (BOP)

equipment and structures.

• General arrangement (GA) drawings were prepared for wet FGD and dry FGD to estimate

approximate quantity of duct material.

• Inputs for specific capital costs for wet FGD and dry FGD were developed by comparison with

historical vendor budgetary quotations for each technology implementation.

• Inputs for O&M costs were developed in paralle l with Entergy. A detailed model projecting

annualized costs for each unit over a 40-year study period was prepared for wet FGD and dry FGD.



# 1.3 STUDY BASIS

The basic data listed below were used as inputs to the study:

• Unit Design Information . Unit size, boiler type, capacity factor, heat input, flue gas temperature,

pressure profiles, and water quality.

• Economic Information . Real interest rate, escalation rate, replacement energy and capacity

charges, and process consumables.

• Fuel Information . Basic fuel properties for Jacob’s Ranch Powder River Basin (PRB) coal.

1.3.1 Unit Design

S&L initiated its evaluation using the heat input to the boile r of each unit provided by Entergy to generate material

balances. Heat input to the boiler is a primary parameter u sed to calculate the quantity of flue gas that would need

treatment at each White Bluff unit. A team of S&L and Ente rgy analyzed the various heat input data and concluded

that 8,950 mmBtu/hr would be anappropriate heat input for the design of the FGD system. This resulted in

approximately a 5% margin on the Unit 1 heat input after the economizer modification and 1% margin on Unit 2

after its economizer modifications in 2008. The amount of fl ue gas that needs treatment is one parameter used to

size emission control technology equipment that would serve as input to the capital cost estimate.

1.3.2 Economic Information

Table 1-1 lists the major economic parame ters used in the financial model.

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## Table 1-1. Major Economic Parameters

Parameter Value

Amortization life, years 40

Interest rate for discounting, % 8.24

Commercial service date Sept 2013

Capacity factor, % 72.0

Debt percentage in capital structure, % 41.97

Preferred stock percentage in capital structure, % 4.44

Equity percentage in capital structure, % 53.59

O&M escalation rate, % 2.0

Debt interest rate, % 6.34

Preferred stock rate, % 5.99%

Capital escalation rate, % 3.0

Federal and state tax rate, % 39.225

Equity return, % 9.90

Annual property taxes and insurance, % 0.944

AFUDC, % 8.24

Tax depreciation schedule Amortized over 84 months

Auxiliary electric power energy charge, $/MWh 47.00

Ash disposal cost, $/ton 8.58

Operating labor rate, $/hr 40.00

Raw makeup water, $/1000 gal 0.92

Cooling tower blowdown water, $/1000 gal 0.48

Lime, $/ton 107.00

Limestone, $/ton 38.00



## 1.3.3 Fuel Information

The study is based on burning typical PRB coal. Based on the coals submitted, a typical operating coal with a sulfur

content of 2 lb SO 2 

## /mmBtu was used for the design. The coal w as based on a heating value of 8,725 Btu/lb. The

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## economic evaluation for SO 2 

## control technology was assessed at 2 lb SO 2 

## /mmBtu design sulfur and 0.8 lb

SO 2 

## /mmBtu operating sulfur as a baseline. A sensitivity analys is was performed for design sulfur levels at 3 lb

SO 2 

## /mmBtu (operating at 0.8 lb SO 2 

## /mmBtu) and 5 lb SO 2 

## /mmBtu (operating at 5 lb SO 2 

## /mmBtu) for wet FGD,

and at 3 lb SO 2 

## /mmBtu for dry FGD. Dry FGD would not be competitive at 5 lbs SO 2 

## /mmBtu.

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# 2. SULFUR REDUCTION TECHNOLOGY EVALUATIONS

2.1 PURPOSE

The purpose of the sulfur reduction technology evaluations is to develop a conceptual design for retrofitting a wet

or dry FGD technology for White Bluff Station, then to compare the economics of each technology, and finally to

recommend the technology best suited for appli cation. The economics identify the cost of SO 2 

## removal based on a

net present value (NPV) assessment and normalized cost for $/ton of SO 2 

## removed.



# 2.2 TECHNOLOGY DESCRIPTIONS

FGD technology has been applied in the U.S. since the 1960s and, with the nearly 40 years of development, it is

considered a mature technology. A wide range of FGD technologies is available. Table 2-1 lists the various types of

utility power plant FGD installations in the U.S. As shown in this table, wet FGD, with either limestone or lime as

the reagent, is the most prevalent, with almost 75% of the total flue gas scrubbing capacity. Dry lime FGD,

typically used when sulfur levels are less than 2 lb SO 2 

## /mmBtu, is the next most selected technology with over 15%

of all installations. This section discusses wet limest one FGD and dry lime FGD technology in detail.

Table 2-1. FGD System Deployment in U.S.

FGD Type Boiler Units (No.) Installed FGD Units (%)

Wet limestone 105 48

Wet lime 58 26

Dry lime/SDA 35 16

Sodium carbonate 9 4.1

Dual-alkali 6 2.7

CDS 5 2.2

Wellman-Lord 4 1.8

Mag-Ox 3 1.4

Dry aqueous carbonate 1 0.5

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## 2.2.1 Lime Spray Dry FGD (LSD FGD)

The LSD FGD technology was developed beginning in 1977, to serve users of low-sulfur coal who had to meet a

requirement of only 70% SO 2 

## removal. As the technology’s experience grew and matured, it demonstrated much

higher performance capabilities and now can provide as much as 95% SO 2 

## removal in many applications.

Gradually, it has been adopted by users of medium-sulfu r coals, and now is frequently considered for mediumsulfur coals of 3 lb/mmBtu SO 2 

## content. Maximum spray dryer absorber (SDA) vessel size had an equivalent

capability of 150 MW of flue gas in the initial installations, but absorber vessels have grown to an equivalent of

350 MW of flue gas.

2.2.1.1 Description of Process

In an LSD FGD system, flue gas is brought into contact with lime slurry in the S DA vessel. This process can use

(pulverized) hydrated lime (Ca(OH) 2 

## ) or (pebble) quicklime (CaO); however, large quantities of lime are

consumed, so the more economical quicklime generally is u sed at large utility installations. CaO must be hydrated

before use. This hydration occurs in a slaker, where lim e is mixed with water and slurry of fine lime particles

results. The chemical reaction is as follows:

CaO + H 2 

## O ↔ Ca(OH) 2



## SO 2 

## absorption takes place in an S DA. Calcium reacts with the SO 2 

## to form waste solids sulfate (CaSO 4 

## ) and sulfite

(CaSO 3 

## ), as shown in the following chemical reaction scheme. About one-third of the waste is sulfate and twothirds is sulfite.

CaO + H 2 

## O ↔ Ca(OH) 2



## Ca(OH) 2 

## + SO 2 

## +H 2 

## O → CaSO 3 

## • 1 

## / 2 

## H 2 

## O + 3 

## / 2 

## H 2 

## O

CaSO 3 

## • 1 

## / 2 

## H 2 

## O + 3 

## / 2 

## H 2 

## O + 1 

## / 2 

## O 2 

## (flue gas) → CaSO 4 

## • 2H 2 

## O



## The dried solids are entrained in the flue gas and exit the SDA, along with the fly ash, and are collected in a fabric

filter. Most of the SO 2 

## removal occurs in the spray dryer vessel itself, although some additional SO 2 

## capture occurs

in the downstream baghouse. A dry FGD without a fabric filter will be limited to about 75% SO 2 

## removal, but with

a fabric filter 95% SO 2 

## removal is achievable.

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## The SO 2 

## removal efficiencies of the existing LSD systems range from 85-95%, depending on the SDA inlet SO 2



## concentration. The effectiveness of spray dryer technol ogy decreases with fuel sulfur levels above 3 lb SO 2 

## /MMBtu

(as shown in Figure 2-1). At higher sulfur levels , the amount of sorbent required for removal of SO 2 

## from the gas

stream increases substantially, and the economics generally favor wet scrubbing. The curve in Figure 2-1 represents

the amount of SO 2 

## reduction expected for an LSD system with a baghouse. This is a general guideline for

application of LSD technology, and is derived from S&L’s in-house database on the technology’s performance,

which is based on guarantee data provided from various suppliers of FGD systems.

Figure 2-1. Relationship Between SO 2 

## to Dry FGD and SO 2 

## Reduction Efficiency

70 75 80 85 90 95 100

0123456

lbs SO 2 

## /mmBtu% SO2Removed



## The primary operating parameters that affect SO 2 

## removal using LSD FGD are:

• The lime stoichiometric ratio (SR) varies with the amount of SO 2 

## in the SDA in the flue gas. The

SR can range from 1.2 lb-mole lime/lb-mole of SO 2 

## at the inlet to 1.6 lb-mole lime/lb-mole of SO 2 

## at the inlet. An SR value of 1.2 is applicable for inlet SO 2 

## values of less than 1 lb SO 2 

## /mmBtu,

while the larger value is for inlet SO 2 

## values greater than 2 lb SO 2 

## /mmBtu.

• The flue gas temperature into the SDA is important. Temperatures above 300 ° F allow more water

and lime to be injected with the flue gas. This increases SO 2 

## removal and the utilization of the

lime. If the inlet temperature is below 300 ° F, the efficiency will be reduced.

• The flue gas temperature at the SDA outlet, also known as the approach to saturation

temperature , is designed to be 30 ° F above the saturation temperature. Operating at a 20 ° F

approach temperature can increase removal efficiency but at the risk of water condensation in the

baghouse, which can cause operating problems.

2.2.1.2 Discussion of Features

Figure 2-2 depicts a typical dry FGD system. The LSD FGD includes several subsystems:

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## • Reagent handling and preparation

• Absorption in a spray dryer absorber

• Particulate collection

• Flue gas system and stack

• Waste handling system and disposal

Figure 2-2. Typical Dry FGD System

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## 2.2.1.2.1 Reagent Handling and Preparation

Lime is conveyed by truck, barge, or rail to an enclo sed storage silo. A detailed study will be performed if dry

technology is selected for White Bluff. Utilities usually requi re a storage capacity of at least seven days, depending

on the delivery method and lime source proximity. For deliv ery by truck, the maximum recommended silo height

should be 120 feet if the truck’s onboard blowers are used for unloading. However, the lime supplier should verify

the capability of the truck blowers to transport the lime. If the silo needs to be taller than 120 feet, a permanent

pressurized blower system needs to be installed.

For lime delivered by truck, silos are usually sized for a 7- to 14-day capacity, 7 days if the lime source is close to

the power plant and 14 days if a distant source is used. A 14-day capacity silo with truck delivery is used for this

study. The bulk storage silo feeds directly into the lime-sl aking train and no transfer system is needed. Delivery by

truck may not allow for competitive bidding to supply lime if one source is significantly closer to the plant. Rail

delivery allows for more sources to be considered.

For delivery by rail, larger quantities of lime are stored on site. Durations of 14 days or more have been the norm

for most utilities. The strategy for selecting the storage cap acity depends on the railroad used and the number of rail

cars that the site can handle. Some utilities receive an entire unit train of lime, while others receive one-third or onehalf of a unit train.

The lime silo has either a bin activator or a fluidizer to promote lime flow ability. A rotary feeder in series with a

volumetric feeder supplies the lime to a slaker, wh ere the pebble lime, CaO, is hydrated to Ca(OH) 2 

## . The slaking

process is exothermic and the heat release helps to shatter th e lime into fine particles. The slaked lime slurry then

flows to a storage tank where it is held un til it is needed by the atomization process.

Truck-delivered lime will remain in large pieces when it enters the slaker, but lime pneumatically transferred

several times is likely to be in a powdered form. The slaki ng water must be at least 60°F so the slaking process is

not cooled and slowed down. The slaking water also must be less than about 190°F so that the slaking process does

not boil.

Slaker types that are used in this pr ocess include detention, attrition, horizontal ball mill, and vertimill slakers. The

detention slaker consists of a vessel equipped with an ag itator that disperses the heat released during the reaction.

Without the agitator, high temperature areas may form resulting in steam formation that may damage equipment.

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## The vessel is also fitted with a classifier section that sep arates the sufficiently slaked particles from the coarse lime

particles. The larger particles are recy cled back to the slaker vessel while gr it material, consisting of inert material

as well as uncalcined limestone and magnesium oxide particles, is removed.

An attrition slaker is comprised of a vessel and a set of agitators with a common axle, which produce a counter

current flow that induces lime particle interaction in or der to speed up the slaking process. The main difference

between detention slakers and attrition slakers is the degr ee of solids interaction. Attrition slakers may also be

mated to grinding or grit removal e quipment for impurity removal.

In a ball mill slaker, pebble lime and water is added con tinuously to a horizontal vessel that contains grinding

media, which allows grinding and slaking to occur si multaneously. The product flows through a classifier that

separates the final slaked product from the coarse material, wh ich is then fed back to the ball mill to be processed

further. Due to the grinding function of the ball mill slaker, a grit removal system is not necessary.

A vertimill slaker operates in a similar fashion to the ball m ill slaker, with the exception that the vessel is vertically

oriented and includes a double pitch helix that agitates the grinding media. A classifier system is also used to

recycle the coarse product back to the grinding vessel. Si milarly to the ball mill slaker, the vertimill does not

require a grit removal system.

The advantage of the ball mill type slakers is the less stringent requirements for quicklime size and slaking water

quality, as well as eliminating the need for the grit removal system. Although a slaker type has not been specified,

the horizontal ball mill was used in the cost evaluation fo r the slaking process. Reagent preparation with two 100%

slurry trains is used for this study. Each train is made up of a solo, feeder, and slaker. The slurry is stored in a

dedicated storage tank.

2.2.1.2.2 Recycle Ash System

A portion of the waste solids from the baghouse will be sent to the recycle silo. The recycle silo is located above the

waste slurry preparation area. From the recycle silo, the dr y waste flows to premix tanks where it is combined with

water. The slurry overflows first to recycle holding tanks, and then overflows into recycle slurry storage tanks. The

recycle storage tank solids concentration is approximately 40% by weight. This recycle system allows the lime to

be passed through the SDA several times to reduce lime cons umption. The recycle train is important in achieving

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## high SO 2 

## removal efficiencies. There is residual activity left in the lime after it has b een passed through the system

once; therefore, it is re-introduced to gain additional lime utilization.

2.2.1.2.3 Spray Dryer Absorber

The SDA is a vertical, open chamber with concurrent contact between the flue gas and lime slurry (Figure 2-3). The

slurry is injected at the top of the tower using either a rotary atomizer or a dual-fluid nozzle, which produces fine

droplets to absorb the SO 2 

## . In the process of evaporating the droplets, th e flue gas is cooled from the absorber inlet

temperature of approximately 318 ° F to an outlet temperature of 160-180 ° F depending on the adiabatic saturation

temperature. The actual outlet temperature is chosen based on the optimum reagent utilization, the flue gas

saturation temperature, and the required SO 2 

## removal efficiency. The absorber typically will be operated at 30 ° F

above the gas saturation temperature (also known as the a pproach temperature) to prevent solids deposition on the

walls of the absorber and to avoid mois ture condensing in the particulate collector. The residence time of the cooled

flue gas in the SDA should be at least 10 seconds to ensure high removal efficiencies. Most current designs utilize a

residence time of over 12 seconds.

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## Figure 2-3. Typical SDA (B&W)

Source: Babcock & Wilcox



## The slurry comes into contact with the flue gas inside the SDA vessel, and the slurry should be dry before it

contacts the SDA wall. Corrosion of the SDA walls can occur if a high-chloride coal is fired; however, this is rarely

a concern with Powder River Basin (PRB) coals. Because the flue gas exiting the SDA typically is held at 30 ° F

above saturation, carbon steel ductwork is adequate and alloys are not needed. Therefore, the downstream ducts,

baghouse, and chimney liner can all be made of car bon steel. Precautions should be taken around access doors and

other penetrations where cool ambient air can leak into th e duct and form cool spots in the SDA where acids in the

flue gases can condense. In these locations, it is common to spray a coating over the carbon steel for a minimal

amount of corrosion protection.

The dry absorber does have some capability to remove merc ury from the flue gas, but the mercury must be in the

ionic form to be absorbed. PRB coal is low in chlorides and the mercury from firing PRB is not in the ionic form,

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## but rather, is mostly in the elemental form. However, dry FGD has potential to remove significant amounts of

mercury if the elemental form can be converted to the ionic form in the flue gas. Coal additives have completed this

conversion of elemental to ionic mercury. Coal additives c ould be a halogen, such as bromine or iodine. Tests to

date have shown that anothe r halogen, chloride, is the least effective of these compounds, but bromine or iodine

have been effective in utility tests. Dry FGD has the poten tial to capture 70-80% of the mercury in the PRB coal if

additives are used. Additives are believed to be less expensive than powdered-activated carbon.

The SDA vessel will have a discharge hopper on the bottom to allow any small material buildup on the walls to

slide down and to be removed.

2.2.1.2.4 Particulate Collector

The SDA typically is located after the air heater outlet, a nd needs to be followed by a particulate collector, which is

almost always a baghouse. Dry FGD systems usually are coupled with a fabric filter baghouse because SO 2 

## removal

efficiencies up to 95% are then possible. A substantial amount of the SO 2 

## is removed in the baghouse because the

lime rich product and fly ash remain on the surface of the bags and the flue gas is pulled through this layer of lime.

This close contact between the flue gas and lime accounts for another 10-15% of the overall SO 2 

## removal.

A pulse jet baghouse (Figure 2-4) with an air-to-cloth ratio of 3.5 ft/min (1.1 m/min) typically is used downstream

of a dry-FGD system on coal-fired units. The baghouse is provided with a spare compartment for routine

maintenance. The waste is pneumatically conveyed to a w aste storage silo with typically a 3-day storage capacity.

The baghouse or ESP casing must be well insulated to contain the heat within the casing and to keep the interior

skin temperature about 30°F above saturation.

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## Figure 2-4. Typical Pulse Jet Fabric Filter

Source: Wheelabrator



## 2.2.1.2.5 Waste Handling

The waste collected in the baghouse is pneumatically tran sported to a storage silo. A portion of the waste is

recycled to increase the reagent utiliza tion. The dry FGD waste is mixed in a pug mill with water to prevent dusting

if being transported in open top (tar p covering) style trucks for disposal . Sale of the waste products from dry

scrubbing is rare and the material is typically sent to a landfill. Dry FGD waste contains r eacted calcium compounds

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## and unreacted lime, Ca(OH) 2 

## . The waste has pozzolanic properties and when wa ter is mixed with the waste, it cures into

a low-grade concrete. Because this solid product is impermeable, disposal in a landfill is a safe practice. One plant in the

U.S. forms pellets with the waste and sells them as gravel for fill or sub-base.

2.2.1.2.6 Flue Gas System and Stack

Ducts downstream of the SDA can be fabricated out of carbon steel, but the ducts and expansion joints must be

insulated with insulation pillows to contain the heat in the flue gas and maintain the gas at about 30°F above

saturation. The chimney liner typically is insulated but its exit can have cool ambient air pulled down into the top of

the liner under certain atmospheric conditions. The inside of a carbon steel liner is typically coated in the top

50 feet to negate any impact of sulfurous acid condensation.

2.2.1.2.7 Staffing

The conceptual design economic analysis includes 16 add itional people for the O&M of the new dry FGD system,

as summarized below. A detailed listing of the staffing cost can be found in Section 3.5.2.

• Lime unloading will require a crew to move the rail cars or trucks through the unloader and to

connect the equipment to each hopper. This crew w ill work one shift between five and seven days

per week to unload the cars.

• FGD process operations will require an operator to walk down the process equipment and check

for malfunctions. The rotary atomizers will need to be switched on a 60- to 90-day cycle to clean

their atomization wheels and perform other maintenance. Dual-fluid atomizers will be cleaned

weekly.

• Waste loading to truck or rail cars will continue as currently practiced for fly ash. Disposal of

larger amounts of solids will require additional time for these activities.

2.2.2 Wet Limestone FGD with Forced Oxidation (LSFO FGD)

The term wet FGD refers to a system using an absorber that comp letely saturates the inlet flue gas with water. The

flue gas typically is 300°F when it enters the absorber, then the gas is adiabatically cooled to a saturation

temperature between 122-135°F. The flue gas exits the absorb er at the saturation temperature. The saturated flue

gas allows for quick mass transfer of the SO 2 

## gas into the slurry droplets. The slurry droplets are a combination of

limestone and water. Once SO 2 

## is absorbed, it reacts with the calcium from the limestone and the reaction product is

a solid precipitate.

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## Wet limestone FGD systems have been operating in utility applications since the 1960s. Early generations of wet

FGD technology had internal scaling problems that caused the absorbers to be brought off line for cleaning every

few months. To achieve acceptable availability for multi-un it use, many smaller absorbers were installed on one

unit so that one absorber could be taken off line for clean ing and repair while the othe rs handled 100% of the flue

gas. Over the years, utilities learned to combat scali ng problems using two technological advances. The first

advance was to use forced oxidation of the precipitate in the absorber reaction tank, which effectively addressed the

problem of scaling in the absorber. The second advance was to introduce most of the water needed by the process

into the mist eliminators of the LSFO FGD. The water re quired for mist eliminator wash typically has less than

1000 mg/L total dissolved solids and less than 50% saturated calcium sulfates. Service water from a well or lake

usually is acceptable for this application. Cooling tower blowdown and ash pond water are not acceptable. Good

water quality significantly reduces the plugging of the mist eliminators.

These advances solved many of the chemistry problems and made the process much less complex. State-of-the-art

wet FGD systems do not experience scaling issues. Spare abso rber modules are rarely installed and single absorbers

are routinely installed on large units.

Early-generation wet FGD technology experienced signifi cant problems with corrosion of the absorber metals.

Absorbers were coated with rubber or flake glass lined to avoid corrosion, but these systems required very high

maintenance. To avoid high maintenance and to minimize th e corrosion in the absorbers, alloys later were used

inside the absorbers. The alloys ranged from 317 L to C- 276, depending on the level of chlorides in the absorber

recycle slurry. Utilities have identified the reasons for the corrosion and have learned to make better selections of

alloys within the absorber. Developers of alloys have also responded with newer, more corrosion-resistant and

lower-cost alloys. Utilities have also learned that the chlori de level is the most important parameter to monitor.

Modern wet FGD systems use blowdown water from the abso rber to control the chloride concentration in the

scrubber slurry to within the capabilities of the materials of construction. These advances have allowed utilities to

select wet FGD systems that will last fo r several decades with only routine main tenance. Again, this also allows

utilities to use a single absorber for large units.

Waste solids from early-generation wet FGD were difficult to handle and to dewater, and had no value to utilities.

The change to forced oxidation chemistry allowed u tilities to produce gypsum from the wet FGD waste solids,

which does have some value in certain locations. The gy psum dewaters easily to 90% solids and can be easily

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## transported. Gypsum can be washed to remove fly ash and/or chlorides so it can be used for wallboard

manufacturing, or as a soil additive in agricultural areas. W aste solids that are land-filled are dense and inert. Issues

such as leaching and ground water contamination are not a c oncern for land-filling gypsum. It has been shown that

most gypsum is land-filled, but if either of the other two uses is applicable, the gypsum can be sold or given away,

thereby avoiding the land-filling costs.

Wet LSFO FGD systems are the predominant wet FGD technol ogy used by utilities. It is most applicable for

medium- to high-sulfur coals where removal of 95-99% of the inlet SO 2 

## can be achieved. LSFO FGD is also

effective on low-sulfur coals where it can remove 93-95% of the inlet SO 2 

## . Wet FGD systems are limited to a

minimum outlet concentration of between 0.03-0.04 lb/mmBtu of SO 2 

## . Driving the concentration lower is not costeffective.

In summary, the basic wet limestone scrubbing process is now reasonably simple and well-established. Recent

advances in the wet limestone FGD process include design changes to promote SO 2 

## absorption at high removal

rates. After experiencing poor reliability in the first ge neration of this technology during the 1970s and early 1980s,

wet limestone scrubber technology has matured and is now capable of meeting availability levels of 99%.

Additionally, gypsum can now be recovered as a salable byproduct where feasible. Extensive operating experience

has increased industry confidence in designing larger, mo re reliable limestone scrubber modules. Single absorbers

treating 1,000 MW of the flue gas are in operation. In 1994, wet limestone scrubbers were used on 70 units, (35,100

MW

e 

## of the total scrubbing capacity). Today, there are more than 100 operating limestone scrubbers, with more

under construction to meet new emission criteria. LSFO F GD is a viable technology for any coal-fired boiler.

2.2.2.1 Description of Process

In an LSFO FGD system, flue gas containing SO 2 

## is brought into contact with limestone-slurry droplets and the

SO 2 

## is absorbed into the water dr oplet. Within the droplet, the SO 2 

## and calcium from the limestone (CaCO 3 

## ) react to

form calcium sulfite (CaSO 3 

## ). As the slurry falls through the flue gas, it eventually falls into the reaction tank,

where it is stored for a few minutes (typically 6 minutes of li quid residence) before being recirculated back into the

flue gas stream. The reaction tank has agita tors to keep the slurry in solution and also has oxidation air spargers to

force-oxidize the reaction product. The calcium sulfite is force-oxidized to calcium sulfate and the final pr oduct is

calcium sulfate dihydrate (CaSO 4 

## • 2H 2 

## O), commonly known as gypsum. The reactions are:

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## CaCO 3 

## + SO 2 

## → CaSO 3 

## + CO 2



## CaSO 3 

## + 1 

## / 2 

## O 2 

## (flue gas) + 2H 2 

## O → CaSO 4 

## • 2H 2 

## O



## Before the use of forced oxidation, the bisulfite ions would be recirculated through the absorber and would scaleout on the internals of the vessel. Force oxidizing the bisulfite ions turns them into a precipitate in the reaction tank

so it cannot scale out onto the internals of the absorber.

Most of the solids are recycled through the absorber several times, and a small bleed stream is sent to a dewatering

step. Vacuum drum or belt filters are used to concentrat e the bleed slurry stream to 85-92% solids. The water from

this process is returned to the FGD pr ocess. If salable-grade gypsum is to be produced, the solids are washed with

clean water to remove the chlorides. This water is also returned to the process.

The absorber is very effective at removing hydrochloric acid (HCl) from the flue gas. The HCl reacts with the

limestone and stays in solution as chloride ions. Chloride ions are very corrosive to ferrous-based metals, thus

carbon steel is not an acceptable metal for construction of th e absorbers. For chloride concentrations of 15,000 ppm

or less, a new stainless steel alloy is being used, alloy 2205. This alloy is used for the lowest-capital cost absorber.

All the internals can be made from this alloy, including s upports, recycle grids, trays, and reaction tanks. In most

cases, recycle piping is not made of alloy, but of fiber-rein forced plastic (FRP) with a wear-resistant coating. PRB

coal has minimal chlorides to be collected, but if a moderate -sulfur coal with higher chlorides is to be considered, a

higher quality alloy could be used at a greater cost.

2.2.2.2 Discussion of Features

A typical wet FGD system comprises several subsystems, including:

• Limestone handling

• Limestone slurry preparation

• Absorber

• Primary and secondary dewate ring and byproduct handling

• Ducts and chimney

Each subsystem is tailored to the specific characteristics of the plant site based on emissions criteria and the sulfur

content in the fuel. These subsystems are diagrammed in Fi gure 2-5, with the operations of each described below.

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## Figure 2-5. Typical Wet Limestone FGD System

Flue gas from

precipitator

or baghouse Limestone slurry scrubbing

absorbs SO 2 to form CaSO 3

Crushed

limestone

Air

Aeration oxidizes CaSO 3 to form crystallized

CaSO 4 • 2 H 2 O (gypsum) Slurry withdrawn to remove gypsum

Gypsum

solids

to filtration Desulfurized flue gas to stack

Slurry recirculated to sprays

Limestone is wet-ground

to produce limestone slurry

Filtrate M

Water Hydroclone

ROTARY DRUM

VACUUM FILTER ABSORBER

BALL MILL Fresh water

Mist eliminators washed

with fresh water Bypass

Day Bin

Gypsum HORIZONTAL VACUUM BELT FILTER OR



## 2.2.2.2.1 Limestone Handling System

Crushed limestone (typically, 3/4 x 0-inch or 1.91 x 0-cm ) received at a plant typically is delivered by bottomdump railcars or trucks and is unloaded into a receiving hopper. It is assumed that limestone will be delivered by

truck at White Bluff. The trucks will unload the limest one to an outdoor, uncovered limestone storage pile. There

are two storage piles - one active pile (30 days’ storage) that feeds the reclaim hopper and one inactive pile that is

used only if limestone deliveries are interrupted. A bulldozer is then used to move limestone between the two piles.

Reclaim of the limestone from the bottom of the active storage pile is by underground reclaim hoppers equipped

with vibrating belt feeders. The feeders supply the recl aim conveyor, which carries the limestone to the day silos

located immediately above the wet grinding ball mills. Ra in water around the active and inactive limestone piles is

handled by installing a drain ditch around the piles where the water can be collected.

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## 2.2.2.2.2 Limestone Slurry Preparation System

Preparation of the limestone slurry involves wet grinding the limestone in a horizontal ball mill. The limestone

received on site is similar to gravel. The limestone day bins and gravimetric feeders deliver the limestone to a

2 x 100%-capacity ball mill system for both units. Figure 2-6 shows typical ball mills. One ball mill runs continuously,

while the second ball mill provides 100% spare capability. The ball mill grinds the limestone and discharges it into a

small receiving tank that is then pumped through hydroclone cl assifiers. The limestone that is 95% less than 325-mesh is

ready for use and sent to a storage tank, but the larger partic les are returned to the ball mills for further grinding and size

reduction. Two 100%-capacity classification pumps are used to ensure high reliability of the classification system.

Process makeup water or recycle water is added to the ball mills to produce 70% by weight solids slurry. The slurry

classification process produces 30% by weight solids slurry, which is stored up to 24 hours until it is fed as reagent

makeup into an absorber. The slurry concentrations are measured using nuclear density meters. The ball mills are

rubber-lined to reduce erosion of the mill internals. Steel ba lls are added as needed to replenish the balls in the mill.

Since White Bluff is located in a warmer climate, the reagent preparation system will not need to be in a building to

protect the equipment and staff from the weather.

Figure 2-6. Typical Ball Mill for Large FGD System



## 2.2.2.2.3 Absorber System

Figure 2-7 depicts a typical absorber (B&W) utilizing a ver tical spray/tray tower concept, with counter-current

contact between the flue gas and scrubber slurry. This counte r-current type is the most commonly used absorber in

the utility industry. Other absorber types available include jet bubbling reactor and co-c urrent/counter-current flow.

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## First-generation absorbers relied on packing to provide th e mass transfer, but in conventional absorbers the mass

transfer occurs in the tray and in the open-spray zone. So me vendors rely on the sprays to provide the mass transfer,

while other vendors use the tray for mass transfer.

The tray is a horizontal perforated plate with a two-foot -tall egg crate on top that causes the slurry to form a

several-inch froth layer on top of the tray. Flue gas that is forced up through the tray, comes in contact with this

froth, and then gives up its SO 2 

## to the slurry. When a tray is present, most of the sulfur collection occurs at the tray

and the spray levels do less of the sulfur collection. One advantage of the tray is that it smoothes the upward flow

of flue gas, evenly distributing the flow so the entire abso rber area is used for sulfur collection. Including a tray in

the design allows reduction of the liquid-to-gas (L/G) ratio. B&W and Siemens both use trays.

An open-spray tower is a second popular absorber design. This type of absorber relies on several spray levels to

create enough droplets to carry out the necessary mass transfer . The L/G ratio for an open-spray tower is greater

than for a tray, and the uniform downward flow of slurry is responsible for spreading the upward flow of flue gas

for uniform flow. Open-spray towers use a baffle around the inside circumference of th e absorber to prevent gas

flow from bypassing the spray zone. Designers of this type of absorber point out that there are no internals in the

absorber to corrode or scale. Alstom and Babcock Po wer Inc. both use open-spray towers. Figure 2-8 depicts

Alstom’s open-spray tower.

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## Figure 2-7. Typical FGD Scrubber with Absorption Tray

Source: Babcock & Wilcox

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## Figure 2-8. FGD Scrubber with Open-Spray Tower

Source: Alstom



## After falling through the spray zone, the slurry accumulates in the reaction tank. Modern absorbers integrate the

reaction tank into the bottom of the absorber, whereas earlier-generation FGD systems used a separate external

tank. The tanks hold the slurry for at least 15 hours (so lids residence time) to allow the reaction between the

limestone and SO 2 

## to complete and let gypsum crystal grow above 20 microns. The reaction tank is agitated to keep

the solids in suspension and air is forced in to the reaction tank to force-oxidize the CaSO 3 

## in the slurry. Fresh

limestone is added to the tank so there is an excess of calci um and all sulfur is reacted. The retention time in the

reaction tank allows all the sulfite to react with oxygen so the solution is not supersaturated with sulfite and bisulfite ions. Without the forced oxidation step, the ab sorber would be susceptible to scaling and would need

frequent cleanings. With forced oxidation, there is no n eed to clean the absorbers of scale that could disrupt

absorber performance.

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## The forced oxidation air is supplied by a set of compressors in the absorber building. Compressed air is injected

below the reaction tank agitators through a sparger networ k to achieve greater than 99% oxidation of calcium

sulfite (CaSO 3 

## ) to calcium sulfate (CaSO 4 

## ). A 3:1 stoichiometric ratio (SR) of oxygen to SO 2 

## is used to size these

air compressors.

From the reaction tank the slurry is pumped back into th e absorber’s spray zone. High-horsepower pumps are used

for the recycle. Conventional absorbers have at least one spare recycle pump to provide high availability of the

absorber. Slurry is sprayed through several headers that span the diameter of th e absorber. Slurry is abrasive and the

spray nozzles are erosion-resistant. Occasionally, a piece of scale can become lodged in the spray nozzle, causing

pluggage or sending the flow in an unpr edicted direction, so many smalle r nozzles are used. The spray header

material is either alloy or FRP, with the latter gaining more use in recent absorber installations.

Above the spray zone is the mist eliminator, which rem oves the entrained slurry droplets so they do not exit the

absorber and create particulate emissions leaving the chim ney. The mist eliminator must be washed with clean

water to remove limestone deposits. Ea rly-generation wet FGD systems attempted to use cooling tower blowdown

or other wastewater, but this caused plugging of the mist eliminators. When high-quality water is used, plugging is

virtually eliminated.

The absorber must be constructed of materials that resi st corrosion, erosion, and scaling. To reduce corrosion when

firing PRB coal, an A-2205 SS alloy can be used so long as the chlorides in the recycl e slurry are maintained

between 8,000-15,000 ppm with typical chloride less than 12,000 ppm. PRB coals usually have a minimal amount

of chloride so this is usually the highest alloy that need s to be considered. The absorb er inlet duct is an especially

corrosive environment because of the we t/dry interface that occurs when some of the slurry deposits on the inlet

floor of the duct. To combat this highly corrosive envir onment, the inlet duct is made of C-276 from the absorber

back about 10 feet. The outlet duct to the chimney is also a location subject to corrosion and either C-276 or FRP is

used for this duct. FRP would be used if the unit is insta lling an FRP liner in the chimney. If FRP is not used in the

chimney, then a C-276 clad duct would be likely.

Wet absorbers generally are ineffective at collecting par ticulate. If a high-efficiency precipitator or baghouse is

ahead of the absorber, the amount of particulate emissions in to the absorber is anticipat ed to be the same as out of

the absorber. A high-efficiency particulate collector ahead of the absorber is beneficial to wet FGD chemistry

because fly ash can add ions to the recycle slurry so lution that can interfere with the absorption process.

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## Because wet FGD systems absorb HCl fro m the flue gas at 99% efficiency, a minimal amount is released to the

environment. Wet FGD systems do not collect SO 3 

## very effectively, and they can cause SO 3 

## to condense as very

fine droplets that can result in a blue plume immediately af ter the flue gas exits the stack if the concentration of SO 3



## exceeds 7-10 ppm. Fortunately, when PRB coal is fired, the amount of SO 3 

## in the flue gas is minimal and a colored

plume will not result. Installation of an SCR will increase SO 3 

## concentrations.

The wet absorber does have some capability to remove merc ury from the flue gas, but the mercury must be in the

ionic form to be absorbed. PRB coal is low in chlorides and the mercury from firing PRB is not in the ionic form,

but rather, is mostly in the elemental form. However, a wet FGD has potential to remove significant amounts of

mercury if the elemental form can be converted to the ioni c form in the flue gas. Coal additives added to the coal

have completed this conversion of elemental to ionic merc ury. Coal additives could be a halogen, such as bromine

or iodine. Tests to date have shown that another halogen, chloride, is the least effective of these compounds, but

bromine or iodine have been effective in utility test s. A wet FGD has the potential to capture 70-80% of the

mercury in the PRB coal if additives are used. Additives are believed to be less expensive than powdered-activated

carbon.

2.2.2.2.4 Primary and Secondary Dewatering and Byproduct Handling Systems

The bleed stream from the reaction tank is pumped to a set of hydroclones for primary dewatering. The hydroclone

overflow is recycled back into the scrubber. The hydrocl one underflow, containing 50% solid s, is fed to a belt filter

for secondary dewatering, as shown in Figure 2-9. Belt filte rs are designed to achieve 90% solids in the gypsum

byproduct to meet the requirements of gypsum buyers, if th e gypsum is being sold to the wallboard industry. The

gypsum cake is washed with fresh water on the belt filters to remove any residual chlorides to a level typically less

than 100 ppm by weight chloride in the dry solids. The wash water used for gypsum cake washing should not

contain chlorides more than 50 ppm if the product is in tended for sale to a wallboard manufacturer. The filtrate

from the horizontal belt filter is returned to the process. If gypsum is disposed in a landfill, a lower-capital-cost

drum filter could be used. The drum filter requires more ma intenance than a belt filter. For example, it can take an

entire shift to change the filter cloth on a rotary drum. Also, agitators can break frequently due to accumulation of

large particles that may enter the drum pan. The rotary drum does not accommodate changes in slurry concentration

very well. Since the cloth is manually bolted in, it wears f aster than a belt filter. A typical rotary drum filter is

shown in Figure 2-10.

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## Figure 2-9. Typical Vacuum Belt Filter



# Slurry feed Cake wash

Product

dischar g e

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## Figure 2-10. Typical Rotary Drum Vacuum Filter



## As mentioned earlier, chlorides are absorb ed from the flue gas and they concentr ate in the recycle slurry solution. A

small blowdown stream may be required to remove chlo rides and other contaminants from the process. If the

gypsum is not being sold, washing the filter cake is not required and chloride-control of the dewatering process is

significantly less complicated. Less costly rotary drum vacuum filters can be used if the gypsum is to be sent to a

landfill, although a water treatment facility will still be necessary to treat the blowdown from the absorber. Landfill

disposal requirements are very site-specific, and depend on parameters such as the actual chemical makeup of the

gypsum waste product, local climate, and soil conditions.

Dewatered gypsum from the belt filter is deposited on a collecting conveyor, then conveyed out of the dewatering

building and stacked on the ground. The gypsum is then loaded into trucks with a front-end loader and then hauled

away.

Gypsum also has potential for reuse, e.g., feedstock for wa llboard manufacturing. For this to be an attractive form

of reuse, a large quantity of gypsum is needed. Utiliti es with 500 MW gross or more of capacity and firing highsulfur coal are likely candidates to pursue wallboard manuf acturing options. These type plants would also need to

be relatively near markets that would be in demand of large quantities of wallboard, such as urban areas. Gypsum

can also be used for agricultural purpo ses, as a soil additive, or as an additive to concrete. Gypsum’s inert nature

renders it viable for land-filling.

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## 2.2.2.2.5 Staffing

The conceptual design economic analysis includes 21 add itional people for the O&M of the new wet FGD system,

as summarized below. A discussion of the staffing costs can be found in Section 3.5.2.

• Limestone unloading will require a couple of pers onnel to move the limestone into the reclaim

hopper underneath the active pile and to m ove the rail cars through the unloader.

• FGD process operations will require an operator to walk down the process equipment and check

for malfunctions. Typical maintenance activities for the FGD system would involve the

conveyors, ball mills, including changing of ball load , recycle slurry pumps, mist eliminator, spray

headers and nozzles, booster fans, hydroclones, rotary drum filters, and waste conveyors.

• Lab Technician/System Engineer for chemistry monitoring.

• Waste loading to trucks will require additional operators. The larger amounts of solids requiring

disposal will also require more time for this activity.

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# 3. COMPARISON OF LSD AND LSFO FGD PROCESSES

3.1 DESIGN BASIS

S&L developed and issued to Entergy separate design b asis documents for dry and wet FGD, as summarized in

Table 3-1.

Table 3-1. Design Basis Used for Dry FGD vs. Wet FGD. Comparison

Parameter Value

Net MW 844 each

Heat input to boiler, mmBtu/hr 8,950

Coal type 100% PRB

Coal composition

Carbon 49.92%

Hydrogen 3.58%

Nitrogen 0.67%

Sulfur 0.87% (2.0 lb SO 2 

## /mmBtu)

Oxygen 12.01%

Moisture 27.72%

Chlorine 0.02%

Ash 5.2%

HHV, Btu/lb 8,725

Flue gas flow, acfm 3,685,000 at 318°F

SO 2 

## removal efficiency 95%

Dry FGD-Specific

Lime stoichiometric ratio 1.1

Lime quality 90% CaO

Lime storage silo 14 days (both units)

Day bin storage 24 hours (both units)

Slakers 2 x 100% (both units)

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## Parameter Value

Absorber 3 x 33%, carbon steel (each unit)

Booster fans 2 x 50% (each unit)

Waste recycling 1 x 100% (each unit)

Waste storage 3 days, 1 x 100% (each unit)

Stack No modifications

Reagent, ton/hr 8.4 (both units)

Trucks per day 10

Waste, ton/hr 17.8 (both units)

Trucks per day 22

Makeup water, gpm 2,100 (both units)

Wet FGD-Specific

Liquid-to-gas ratio 80

Limestone stoichiometric ratio 1.03

Limestone quality 90% CaCO 3



## Limestone storage pile 30 days (both units)

Day bin storage 24 hours (both units)

Ball mills 2 x 100% (both units)

Absorber 1 x 100%, alloy 2205 (each unit)

Booster fans 2 x 50% (each unit)

Primary dewatering Hydrocyc lones, 2 x 100% (both units)

Secondary dewatering Drum filters, 2 x 100% (both units)

Stack 35-foot diameter, 1003-foot height FRP liner (each unit)

Reagent, ton/hr 11.7 (both units)

Trucks per day 15

Waste, ton/hr 22.6 (both units)

Trucks per day 27

Makeup water, gpm 2,520 (both units)

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# 3.2 GENERAL ARRANGEMENT

3.2.1 Lime Spray Dryer (LSD) FGD

S&L developed general arrangement (GA) drawing of major equipment and structures for the White Bluff Station

dry FGD system. The GA drawing for the LSD FGD is presented as Appendix A. This GA was the preferred

arrangement primarily because it minimized the ductwork length between the SDA outlet and the baghouse inlet,

and eliminated turns or elevation changes in the duct. This offers long-term maintenance benefits because the

shorter duct length results in minimizing the amount of solids that can drop out and accumulate on the duct floor.

Implementing the GA will require demolishing White Bluff Station’s Ash Handling Maintenance Building due to

the location of the new spray dryers, and building a new building directly north of the FGD system.

Two lime silos are arranged near the lime preparation area a nd are sufficiently sized to store the reagent for 14 days

of operation. The lime in the bulk storage silo will be pne umatically blown to a day silo located in the reagent

preparation area. Because the reagent preparation area is lo cated near the SDAs, lime slurry will need to be pumped

only a short distance to the top of each SDA.

The recycle portion of the dry FGD process will be local to the prospective unit and not included in the combined

reagent preparation area. A set of silos will be located near the baghouse inlet to receive baghouse recycle fly ash

that will be slurried and re-injected into the SDAs.

Two new booster ID fans will be placed in series with the existing ID fans. The booster fa ns will be sized to handle

the additional pressure drop associated with the dry FGD.

3.2.2 Wet FGD

S&L developed GA drawings of major equipment and st ructures for the White Bluff Station wet FGD system.

Appendix B is a GA showing the major equipment and structures for a wet LSFO FGD system.

The GA was developed based on truck delivery of limestone to the active pile. The limestone unloading, stack-out,

storage in an active pile, storage in an inactive pile, and reclaim are all common to both units. The reagent

preparation area is shown on the GA and will house the ball m ills, classifying equipment, storage of the final slurry

product, and equipment to feed the reagent to the absorber.

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## The absorber vessel for each unit is located to the east of the unit. The duct located after the existing ID fans is the

location of the tie-ins for the wet FGD for each unit. A rather short duct is added to divert the flow to each absorber

area. Two new booster ID fans are then shown to feed a single absorber, which then feeds a single new chimney per

unit. The old chimney could be demolishe d or capped and left in place. If this is the case, routine maintenance will

need to be performed on the chimney for structural inte grity and potential deterioration. The arrangement for the

wet FGD flue gas path is relatively straightforward.

The dewatering system is common for both units and located north of the units. This location allows easy access for

the trucks that will haul away the gypsum byproduct.

The existing ESP and fly ash system will remain as is and ar e unaffected by the retrofit of the wet FGD, because the

wet FGD is downstream of the ESP.



# 3.3 COMPARISON OF SYSTEM FEATURES

3.3.1 Absorber Vessel

The wet FGD system has an advantage in that a single absorber can be used at each unit at White Bluff. Single

absorbers have been built for up to 1,000 MW of flue gas. A single absorber per unit greatly reduces the capital cost

of a wet scrubber.

A dry FGD system uses a spray dryer. For White Bluff Sta tion three SDAs were considered per unit. Some utilities

are starting with SDAs that could be sized for one-half of a White Bluff Station unit’s flow. The feasibility of a

SDA vessel of this large a size has not yet been proven.

A single vessel allows the system to be designed without dampers. This is a significant cost saving and reduces

O&M of dampers and auxiliary power for heated seal air. With two or more vessels, dampers will be included to

allow one absorber to be taken off line for repairs. Without these dampers, the reliability of a two- or three-absorber

system would not be an improvement to a single-absorber system.

Absorber material of construction favors dry FGD syst ems, because they can use car bon steel absorbers without

concerns about corrosion. Wet FGD systems must be built out of corrosion-resistant alloys. With PRB coals, a

lower-cost, lower-grade alloy can be used, e.g., A-2205 SS, because recycle chloride c oncentrations of less than

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## 15,000 ppm are expected inside of the vessel. This alloy is a fairly new material that only recently is being used on

FGD systems. Additionally, the wet/dry interface at the wet absorber’s inlet will need alloy C-276 to protect this

very corrosive location. In general, wet FGD mate rials are more expensive than dry FGD materials.

The single-absorber vessel represents co st savings in wet FGD but the carbon steel materials of construction are an

advantage for dry FGD. Both of these features have been considered in the capital cost estimates completed for

these two technologies.

3.3.2 Chimney

Wet FGD technology typically is installed between the ou tlet of the existing particulate collector and chimney.

However, most retrofit wet limestone FGD units are unable to use the existing chimney, as the chimney typically

would have been designed for hot flue gas at between 70-100 ft/sec exit velocities. To accommodate saturated flue

gas from a wet limestone FGD system, wet stacks typically are designed using a corrosion-resistant flue with a

design gas velocity of 55 ft/sec or less. Adding a new chimney for each unit is deem ed more cost-efficient as

opposed to a common chimney with dual flues for both un its, due to complications with duct work around the

existing coal conveyor. Using one chimney for each un it will minimize expensive ductwork downstream of the

absorber that typically requires either FRP- or C-276- clad liners to avoid corrosion. The capital cost estimate

includes two new FRP-lined chimneys. Reuse of the existing chimney is often a significant cost advantage for a dry

FGD system.

3.3.3 Chemistry

The wet FGD system has a more complex system operating chemistry to monitor than the dry FGD. The wet FGD

scrubber vessel liquor chloride content must be monitored to prevent absorber corrosion. The pH level must also be

monitored to maintain high SO 2 

## removal efficiency and minimum corrosion. Scale oxidation rate is monitored to avoid

scrubber scaling and plugging. However, because the chemistry is relatively constant, it is unusual to have an upset that

causes equipment shutdown.

The dry FGD system does not require as much chemistry m onitoring, but it requires monitoring of the slaking and

recycle trains. The recycle trains mix dry recycled fly ash collected from the baghouse with water, an inherently difficult

task. The recycle system needs frequent attention from operato rs and the trains are taken out of service every week or

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## two. Generally, a dry FGD system needs to be monitored more carefully from hour to hour, whereas, a wet FGD system

operates at a fairly steady pace.

3.3.4 Chloride Blowdown

The wet FGD system absorbs HCl from the flue gas and it is concentrated in the recycle water. The absorber can be

designed for up to 15,000 ppm of chloride without corrosion pr oblems. To limit chloride buildup, some water is blown

down to remove chlorides. This water is often mixed with other plant water and allowed to discharge with other

effluents. If commercial-grade gypsum is to be produced, ther e will be a wastewater stream off the belt filters that will

have to be treated. If the product is to be land-filled, the wastewater will be discharged with the blowdown stream and

will have to be treated as well. Based on the chloride level of 200 ppm in the fuel and the chloride level up to 390 ppm in

the blowdown water, there will be always be a blowdown fro m the wet FGD. The cost es timate therefore includes the

wastewater treatment facility.

Dry FGD does not have a wastewater blowdown stream or a wastewater treatment facility.

3.3.5 Water Consumption

System design calculations for wet and dry FGD systems at White Bluff Station predict that a wet FGD system would

consume 1,260 gallons per minute (gpm) per unit and the dry FGD system 1,050 gpm per unit, while burning 2 lb

SO 2 

## /mmBtu coal. The wet FGD system is estimated to have a waste discharge of 43 gpm per unit that would need to be

chemically treated to precipitate out the metals for the base case. This 43-gpm level can be reduced, if necessary and is

based on land-filling the gypsum. The dry FGD system does not have a wastewater discharge.

3.3.6 SO 2 

## Control

The FGD systems considered have unique capabilities to remove SO 2 

## . As previously stated, a wet FGD is known to

give lower outlet SO 2 

## emissions compared with other FGD system s. Each of the systems can achieve lower

emissions when the unit is at a steady lo ad with a consistent coal. However, as load changes or upsets in the boiler

operations occur, or as coal sulfur varies, so too, do es the outlet emissions of the FGD. Table 3-2 summarizes the

general capabilities of the FGD technologies considered in the study.

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## Table 3-2. Typical PRB Coal SO 2 

## Emissions Expected from FGD Technology

Parameter Lime SDA FGD Wet LSFO FGD

Lowest achievable SO 2 

## emission (lb/mmBtu) 0.06 – 0.08 0.03 – 0.06

Achievable 24-hour average (lb/ mmBtu) 0.12 – 0.15 0.09 – 0.10

Achievable 30-day average (lb/ mmBtu) 0.10 – 0.12 0.07 – 0.10

Achievable annual average (lb/mmB tu) 0.08 – 0.10 0.06 – 0.08



## 3.3.7 Particulate Control

Particulate control is a pivotal issue in selecting dry or wet FGD systems because, although it is not a necessary part

of the wet FGD process, it is integral to a dry FGD syst em. Recently, wet FGD suppliers have provided particulate

control guarantees as low as 0.015 lb/mmBtu with inlet par ticulate up to 0.12 lb/mmBtu. Since White Bluff Station

is equipped with an existing ESP, the particulate emissi ons would be maintained with wet FGD or lowered to

0.015 lb/mmBtu. The baghouse for the dry FGD would be designed to lower the emission to 0.012 lb/mmBtu

giving an advantage to the dry FGD system over the wet FGD.

As for condensable particulate matter, the wet FGD system promotes the condensation of sulfuric acid mist more

than the dry system due to the lower outlet temperature. For either system the condensable particulate is found

assuming 0.8% of the SO 2 

## in the boiler is converted to SO 3 

## , the outlet of the stack would contain 2 ppm of SO 3 

## , or

63 lb/hr; converting this emission to a sulfuric acid mist b asis gives 77 lb/hr of condensable particulate. Even with

the addition of SCR on the unit, the additional conversion of SO 2 

## to SO 3 

## would result in 7 ppm of SO 3 

## , or 289 lb/hr

of sulfuric acid mist. This level is greater than th e current operating permit limit of 261 lb/hr of condensable

particulate matter, a permit revision would then be necessary once an SCR is in place.

Fugitive emissions and additional emission points from an cillary equipment must be taken into account when

choosing an FGD technology. The wet FGD process requir es open limestone and gypsum piles, which adds a

fugitive emission source due to the wind erosion on the open pile. In addition, the truck loading/unloading of the

limestone and gypsum adds a second fugitive emission source. Contrary to this, the dry FGD process does not add

any fugitive emission sources due to the reagent or product, because this material is pneumatically conveyed to the

silos.

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## Similarly to the fugitive emission sources, several tran sfer and emission point sources are added to each FGD

system. Storage silos, common to both types of FGD system s, contribute to particulate emissions, but are controlled

by vent filters by up to 95%. The reactant preparation bu ilding, common to both types of FGD, also contributes to

particulate matter emissions, but ventilation fans reduce th ese emissions by up to 75%. Lastly, the wet FGD system

conveys limestone and gypsum bypr oduct via belt conveyors, which add potential emission points, but dust

suppression system are available that can reduce these emissions by up to 75%.

3.3.8 SO 3 

## Removal

Sulfur trioxide (SO 3 

## ), which condenses to sulfuric acid aerosols in an FGD system, is removed efficiently (greater

than 90%) with a dry FGD/baghouse equipment combination. Wet scrubbers have less affinity for acid mist and

they typically capture between 25-50% of sulfuric acid aer osols, according to FGD suppliers. Alkali injection (i.e.,

Trona) upstream of a particulate collection system or ev en the addition of a wet ESP would be required for a wet

limestone FGD system to achieve the same level of acid mist removal as the inherent removal in a dry FGD system.

S&L would expect alkali injection to be considered BACT for acid mist. The emission of sulfuric acid mist, if

above a threshold value of 7-10 ppm at the stack, may resu lt in a pale blue plume visible after the water vapor

plume dissipates. White Bluff Station fires PRB coal, which has low SO 3 

## concentrations, so a colored plume is not

expected.

The current SO 3 

## emission from the White Bluff units is estimated to be 3 ppmvd (@3%O 2 

## ) or less with 2 lb

SO 3 

## /mmBtu PRB fuel (assuming 0.6% oxidation in boiler, 25% removal across air heater, and 2 ppm across ESP).

With wet FGD, the outlet concentrati on will be approximately 2 ppmvd (@3% O 2 

## ) with 25% removal efficiency

and with dry FGD, the concentration will be less than 1 ppmvd (@3%O2). The advantage of a dry FGD could be

realized only in the case of a future SCR system. If the future SCR system is designed with 3% SO 2 

## –to-SO 3



## oxidation (only with PRB coal), the emissions from the wet FGD could be as high as 9-12 ppmvd SO 3 

## , compared to

dry FGD, which could be limited to 2 ppmvd (@3% O 2 

## ).

3.3.9 Mercury Collection

The dry FGD with baghouse system removes ionic mercury fro m the flue gas. For mercury capture with PRB coal

which would have greater than 80% mercury as elemental mercury, an activated carbon injection (ACI) system or

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## the fuel additive injection to convert elemental mercury into ionic mercury will be required. ACI systems inject

halogenated activated carbon before the SDA and up to 90% removal is expected with a 2 lb/mmacf feed rate.

Similar to dry FGD, wet FGD can remove oxidized mercury. Unfortunately, mercury in PRB coal usually is in the

elemental state, which is not as easily removed. To use the wet FGD capability to remove mercury, a halogenated

(chloride or bromide based) fuel additiv e can be used that converts the elemen tal mercury to the oxidized form. The

mercury can then be captured by the wet FGD. An ove rall removal of 70-80% is possible with wet FGD. To

achieve higher removal efficiency, an additional activated carbon injection system ahead of the ESP or ahead of a

polishing baghouse may be required.

The technology of converting elemental mercury to oxidi zed mercury still needs to mature. However, if this

technology develops as anticipated, an ACI system may not be required if wet FGD systems are installed on the

White Bluff units.

On February 8, 2008, the U.S. Circuit Court of Appeals fo r the District of Columbia rejected the strategy of

regulating mercury emissions through a cap-and-trade program and therefore vacated the Clean Air Mercury Rule

(CAMR). The rejection of the cap-and-trade regulation will co mpel the U.S. EPA to develop a new set of standards

for electric generating units to reduce mercury. It is uncer tain when this will occur, however it is believed it will

take several years.

3.3.10 Preliminary CO 2 

## Considerations for Dry and Wet FGD

The area needed for the CO 2 

## removal system (physical footprint) for a wet FGD is somewhat smaller than for a dry

FGD. This is primarily due to the fact that CO 2 

## removal on a unit equipped with a dry FGD requires adding a wet

chimney since the gas has to be fu rther cooled before entering the CO 2 

## equipment. The CO 2 

## equipment requires a

pre-scrubber/cooler to obtain SO 2 

## emissions below 10 ppm, which is the maximum inlet SO 2 

## concentration into a

CO 2 

## absorber to reduce sulfur contamination. Therefore treatment to remove additional SO 2 

## would be needed on

both systems. Since dry FGD cannot achieve SO 2 

## emissions as low as wet FGD, higher operating cost would be

required for the pre-scrubber connected to the dry FGD. The CO 2 

## physical footprint includes areas for the CO 2



## removal processes: the pre-cooler and absorber area for separating the CO 2 

## from the gas stream, a regenerator area

to renew the scrubber solution, and a compressor area for storage of the CO 2



## .

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## A wet FGD system produces more CO 2 

## than a dry FGD due to the chemical reactions with calcium carbonate

(CaCO 3 

## ), the release of one mole of CO 2 

## is accomplished for every mole of SO 2 

## absorbed. The CO 2 

## is formed

through the decomposition of limestone (CaCO 3 

## ) to form calcium sulfite (CaSO 3 

## ). CO 2 

## makes up approximately

44% by weight of the limestone, depending on purity. Theref ore for each ton of limestone consumed, there will be

approximately 0.44 tons of CO 2 

## formed. With the operating case of an inlet concentration of 0.8 lb SO 2 

## /mmBtu a

total of 11.7 tph of limestone would be consumed for both units combined, which translates to 5.1 tph of CO 2 

## , from

both units. This totals 45, 100 additional tons of CO 2 

## per year from White Bluff. To put this in perspective, the

combustion-based CO 2 

## emissions for the White Bluff units total slightly over 16 million tons per year combined.

Therefore, the CO 2 

## produced from the presence of CaCO 3 

## is very minimal when compared with the CO 2 

## emissions

from the combustion of coal. The combustion of the coal produces roughly 940 tph per unit at White Bluff Station,

while the added CO 2 

## produced in the wet FGD system is less than 1% of this total.

The dry FGD uses lime, which has no added production of CO 2 

## in its use. Noteworthy is that lime is a product of

limestone and even though dry FGD is not emitting CO 2 

## , the kiln that is producing the lime (CaO) generates CO 2



## from the gas driven off the limestone when heating it to 2000-2400°F. One mole of CO 2 

## is driven off for each mole

of limestone consumed; this results in more CO 2 

## being produced in forming lime than it does in using limestone as

a reagent. Additionally, there is fuel c onsumed to produce the heat, which emits CO 2 

## , and the motors that drive the

mechanical portion of the process require energy; this drives the CO 2 

## emitted from the life cycle of lime to a level

exceeding limestone, but the release point is moved to the lime supplier and Entergy woul d not be concerned with

this emission.



# 3.4 COMPARISON OF CONSUMABLES AND WASTES

3.4.1 Power Consumption

The O&M costs presented herein account for power cons umption. The wet FGD consumes 8.9 MW and the booster

fan consumes 5.1 MW, for a total of 14.0 MW per un it. The dry FGD consumes 4.6 MW and the booster fan

contributes 6.8 MW, for a total of 11.4 MW per unit. When a 3 lb SO 2 

## /mmBtu coal is fired, the total power

consumption is increased to 16.3 MW for the wet and 11. 8 MW for the dry system. Overall power consumption is

lower for the dry FGD system than for the wet FGD system.

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## 3.4.2 Reagent Consumption

Dry FGD systems use a more expensive reagent (quicklim e or hydrated lime) than limestone-based FGD systems

(more dollars per mole of calcium), and the reagent must be stored in a steel or concrete silo. Limestone can be

stored outdoors in a pile and moisture is not a problem in its reactivity. The wet FGD system consumes 5.9 tph of

reagent per unit, while the dry FGD system consumes 4.2 tph of reagent per unit.

Reagent utilization for a dry FGD system is poorer compared to a wet limestone system meaning the reagent SR for

a dry FGD system is higher than the SR for a wet limestone FGD system (on the same basis) to achieve comparable

SO 2 

## removal (more moles of calcium per mole of sulfur dioxide). The cost of reagent is provided for in the O&M

costs presented herein.

3.4.3 Waste Byproducts

For dry FGD systems, the resulting byproducts are in dry fo rm and can be handled with conventional pneumatic fly

ash handling equipment. The dry FGD waste containing CaSO 3 

## • 0.5H 2 

## O, CaSO 4 

## • 2H 2 

## O, Ca(OH) 2 

## , and fly ash is

land-filled similarly to waste containing just fly ash. This ma terial is stable in the landf ill and could be fixated with

fly ash to make it less permeable. Wet FGD waste is 99% CaSO 4 

## . 2H 2 

## O, which would be land-filled. Again, the wet

FGD waste can be fixated with fly ash and addition of lime to make it less permeable. Currently, most utilities can

dispose both of these wastes in a lined landfill.

Additionally, there is no liquid waste from a dry FGD system, whereas wet FGD systems typically produce a liquid

waste stream, depending on the disposition of the byproduct. In the case of the White Bluff Station, a wastewater

treatment plant may be required to treat the liquid waste pr ior to discharge due to the high chloride level of the

makeup water from cooling tower blowdown. The wastewater treatment plant produces a small volume of solid

waste, rich in heavy metals (including oxidized mercury) that can be disposed of in a typical landfill. A dry FGD

system can provide an outlet for process wastewater from ot her parts of the power plant. Since the dry FGD system

evaporates all its water, heavy metals, including oxidi zed mercury, are present in the FGD byproduct. The

byproducts tend to trap the trace metals and the concentr ations are low enough to qualify the byproducts for typical

landfills.

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# 3.5 SULFUR REDUCTION TECHNOLOGY COST EVALUATION

3.5.1 Capital Cost

S&L’s capital cost estimates for a retrofit dry FGD and a retrofit wet FGD system for White Bluff Units 1 and 2

encompass the equipment, material, labor, and all other re quired direct costs. The underlying assumption is that the

project will be implemented on a multiple contracting basis. The capital costs are based on burning 100% PRB

coal. The capital cost estimates provided herein are “total plant cost,” and include the following:

• Equipment and material

• Installation labor

• Indirect field costs and BOP engineering

• Contingency (20%)

• Erection contractor profit (at 10% of material and labor)

• General and administration (at 5% of material and labor)

• Freight

• Allowance for funds used during construction (AFUDC [8.24%])

• Sales/use tax (not included)

• Startup and commissioning

• Spare parts (1% of equipment)

License fees and royalties are not expected for the proposed control strategies. The capita l costs are summarized in

Appendixes C and D for dry and wet FGD, respectively.

The capital cost estimates for installing dry FGD or wet F GD at White Bluff Units 1 and 2 include the following:

3.5.1.1 Reagent Handling and Preparation System

3.5.1.1.1 Wet FGD

• Limestone delivered by truck

• Long-term limestone storage for 30 days

• Ball mills provided to grind the limestone

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## • Slurry storage tank with 24 hours of capacity

• Slurry feed pumps for each absorber

• Slurry pipe loops for the Units 1 and 2 absorbers

3.5.1.1.2 Dry FGD

• Lime delivered by truck

• Silos for long term storage, 14 days

• Ball mill slakers

• Slurry storage tank with 24 hours of capacity

• Feed slurry pumps

3.5.1.2 Absorber Systems

3.5.1.2.1 Wet FGD

• 1 x 100% absorber for each unit

• Spray headers along with one slurry recycle pump for each header

• Oxidation air compressors for each unit

• 2205 alloy absorber, wet/dry interface – solid C-276, and outlet duct C-276 clad

3.5.1.2.2 Dry FGD

• 3 x 33.3% absorbers for Unit 1 and 3 x 33.3% absorbers for Unit 2

• Pulse-jet baghouse, 3.5:1 air-to-cloth ratio, one for each absorber

3.5.1.3 Flue Gas Systems

3.5.1.3.1 Wet FGD

• Inlet (carbon steel) and outlet (C-276-lined) ducts for each absorber

• Bypass dampers

• 2 x 50% booster induced draft (ID) fans for each unit

• Wet chimney with FRP liner for each unit

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## 3.5.1.3.2 Dry FGD

• Inlet and outlet ducts (carbon steel)

• 2 x 50% booster induced draft (ID) fans for each unit

3.5.1.4 Byproduct/Waste Handling

3.5.1.4.1 Wet FGD

• Hydroclone separator for each unit

• Slurry pipeline from each absorber

• Rotary drum vacuum filters

• Stackout conveyors

• Wastewater treatment - minimal

3.5.1.4.2 Dry FGD

• Waste recycle system

• Waste conveying system

• Silos with 3 days of waste storage capacity

• Dustless unloaders

3.5.1.5 Electrical/Instrumentation

3.5.1.5.1 Wet/Dry FGD

• Transformers

• Switchgear

• Instrumentation

3.5.1.6 Makeup Water Supply/Wastewater Treatment

3.5.1.6.1 Wet/Dry FGD

• Makeup water treatment facility

• Water storage tank

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## 3.5.1.7 Balance-of-Plant

3.5.1.7.1 Wet/Dry FGD

• Compressor for instrument air, service air

• Foundations, steel, demolition, relocations, new storage warehouse, etc.

• Roads, storm drainage, etc.

3.5.2 Fixed and Variable Operating Costs

The fixed O&M costs determined for this study cons ist of operating labor, maintenance labor, maintenance

material, and administrative labor. The wet FGD will requi re an estimated 21 additional full-time operators and

maintenance personnel and the dry FGD will require an estimated 16 additional full-time operators and

maintenance personnel for each shift for both units.

The operators would be looking after the absorber syst em, reagent preparation, and byproduct/waste system. The

limestone receiving/handling will also require an operato r. The existing shift supervisors will handle added

responsibility for the FGD system. Due to existing work load on the plant chemist, an additional lab technician will

be added for the FGD system.

S&L’s estimated staffing levels for White Bluff are as shown in Table 3-3.

Table 3-3. FGD System Labor Requirements

Staff Dry FGD Wet FGD

Reagent unloading 2 2

Absorber 10 10

Dewatering/reagent preparation 0 5

Gypsum handling 0 2

Recycle/fly ash handling 3 0

Laboratory technician 0 1

System engineer 1 1

Total Staffing 16 21

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## Annual maintenance material and labor costs shown here in have been estimated based on technology operating

experience in the U.S. The annual maintenance cost includ es maintenance material for various subsystems and the

labor required to perform the maintenance. The annual main tenance material and labor is 0.07% and 0.065% of the

initial equipment cost in the capital cost estimate for wet and dry FGD respectively.

Variable O&M costs determined for each application include the cost of consumables, including reagent (lime or

limestone), byproduct management, water, and power requirements. These costs have been calculated based on the

capacity factors provided by Entergy.

The O&M cost basis with 0.8 lb SO 2 

## /mmBtu as operating sulfur is shown in Table 3-4:

Table 3-4. O&M Cost Basis (both units combined)

Parameter Wet FGD Dry FGD Cost ($)

Limestone, t/h 11.7 0 38.00 $/ton

Lime, t/h 0 8.4 107.00 $/ton

Waste disposal, t/h 22.6 17.8 8.58 $/ton

Auxiliary power, MWH 28.0 22.8 47.00 $/MWH

Water, gpm 2,522 2,100 0.92 $/1000 gal

Bag replacement 0 Every 3 years 110 per bag



## The following basis was used to cal culate net present value (NPV):

• Evaluation period - 40 years

• Discount rate - 8.24%

• Capital cost escalation rate - 3.0%

• O&M cost escalation rate - 2.0%

The variable cost for the wet FGD assumes that any generated gypsum is land-filled and will not be saleable.

However, gypsum is potentially saleable. The variable cost for the dry FGD assumes that all generated solid waste

will be land-filled.

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## Also note that for the wet LSFO FGD and dry FGD, reagent cost and byproduct management cost are at 95% SO 2



## removal. Wet FGD is capable of 98% SO 2 

## removal, but the system comparison is based on 95% as the compliance

with SIP requires the emission limit of 0.15 lb SO 2 

## /mmBtu.

Auxiliary power costs developed reflect the additional power requirements associated with operation of the new

booster ID fans as well as the estimated power consumpti on for the absorber, reagent preparation, and byproduct

handling areas.

3.5.3 Preliminary Cost Summary

Based on the economic parameters – the total capital cost, fixed O&M cost, and variable O&M cost – a financial

model was developed to calculate the NPV and levelized annualized cost to determine a low-cost solution. The

model input and results for the base case are presented in Appendix E, which summarizes a comparison of wet and

dry FGD installation costs for two units.

Table 3-5. Summary Comparison of Wet and Dry FGD Levelized Costs (yr. 2013) for White Bluff Units 1 & 2

Cost Parameter Wet FGD -

Limestone Dry FGD With

Baghouse

Capital cost, M$ ($/kW) 744.8 (441) 706.9 (419)

Fixed O&M cost, M$/yr ($/kW-y r) 8.4 (4.95) 7.1 (4.22)

Variable O&M cost, M$/yr ($/MWh) 17.4 (1.58) 19.9 (1.81)

Total O&M cost, M$/yr 25.8 27.0

NPV, M$ 1,484 1,449

Differential, M$ 35 0

Annualized cost, M$/yr 113.8 111.1

Differential, M$/yr 2.7 0

Note: Discount rate of 7.67% was used for the levelized cost.



## Based on the NPV analysis, it can be concluded that dry FGD is the low-cost soluti on, with less than 1.0%

difference between wet and dry FGD.

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## 3.5.4 Sensitivity Analyses

Sensitivity analyses were performed with the following key parameters:

• Evaluate impact of burning higher-sulfur fuels - 3 lb SO 2 

## /mmBtu and 5 lbs SO 2 

## /mmBtu.

• Evaluate impact of low-cost reagent delivery by train.

• Evaluate impact of two-absorber module design for dry FGD.

• Evaluate impact of mercury control with ACI for future Hg-MACT.

• Impact of SCR - related to sulfuric acid control.

3.5.4.1 Evaluate Impact of Burning Higher-Sulfur Fuels – 3 lb SO 2 

## /mmBtu and 5 lb SO 2 

## /mmBtu

The economic analysis was performed with a variation in the fuel levels of SO 2 

## subjected to scrubbing. Figure 3-1

summarizes the impact due to the changes in SO 2 

## operating levels.

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## Figure 3-1. Impact of SO 2 

## in Fuel on Levelized Cost

107.08 113.78 120.47 160.85

108.42 111.06 113.71

100 110 120 130 140 150 160 170

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr

Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0



## The base case comparison for 2 lb SO 2 

## /mmBtu (operation at 0.8 lb SO 2 

## /mmBtu) indicates that the dry FGD would

cost approximately 1.0% lower cost than wet FGD. The ma in difference is due to the cost differential between lime

and limestone. The annual differential in O&M cost due to reagent cost of more than $3.4 million negates the

higher capital cost for wet FGD. The differential is highe r at 3 lb/mmBtu coal predominantly due to somewhat

higher cost associated with capital for wet FGD syst em. Again, the O&M cost was based on 0.8 lb SO 2 

## /mmBtu.

3.5.4.2 Evaluate Impact of Low-Cost Reagent Delivery by Train

The delivery of reagent by train results in savings of al most $10/ton in transportation cost. It is assumed that the

infrastructure to deliver the lime or limestone may cost an additional $10 million in capital expenditure. At this

cost, the differential between dry FGD and wet FGD remain s the same as the base case. It appears that if the capital

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## cost of rail delivery is lower than $10 million, the reagent cost saving due to lower-per-unit cost could be justified

with rail delivery. The results are shown in Figure 3-2.

Figure 3-2. Impact of Rail Delivery on Levelized Cost

107.22 113.96 120.70 155.60

108.82 111.49 114.17

100 110 120 130 140 150 160

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr

Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0



## 3.5.4.3 Evaluate Impact of Two-Absorber Module Design for Dry FGD

The dry FGD system is based on the use of three abso rber modules. Alstom had proposed two modules on units

with a similar gas flow in the past. However, B&W and Siemens had utilized three modules. The use of two

modules will save a significant amount of ductwork, foundations, and structural steel cost. The sensitivity analysis

performed with the use of the two-module scenario resulte d in approximately 7% savings in capital cost, as shown

in Figure 3-3.

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## Figure 3-3. Impact of Two Dry FGD Absorber Modules on Levelized Cost

107.08 113.78 120.47 160.85

103.21 105.72 108.22

100 110 120 130 140 150 160 170

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr

Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0



## By lowering the capital cost for dry FGD by 7%, the a nnualized cost differential reduces to 2% from 6.5% still

favoring wet FGD. However, if the sulfur level drops to approximately 1.5 lb SO 2 

## /mmBtu, the dry FGD becomes

cost-competitive.

3.5.4.4 Evaluate Impact of Mercury Cont rol with ACI for Future Hg-MACT

The base dry and wet FGD system design is based on the use of high-sulfur PRB coal. The PRB coals generate

greater than 80% elemental mercury, which is difficult to cont rol with wet or dry FGD. It is indeed possible that the

Hg-MACT may require 90% mercury removal. The dry FGD will require ACI to achieve the desirable target. For

wet FGD, the use of ACI either ahead of the existing ESP or ahead of a new compact baghouse (compact hybrid

particulate collector [COHPAC]) may be required. For 5 lb SO 2 

## /mmBtu fuel, it is assumed that there is enough

chloride in the fuel to achieve an overall 90% mercur y removal efficiency. If it is assumed that 90% can be

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## achieved (similar to regulations in Illinois), by ACI ahead of the ESP for wet FGD, the sensitivity is as presented in

Figure 3-4.

Figure 3-4. Impact of Mercury Control with ACI for Future Hg-MACT on Levelized Cost

126.59 135.15 141.84 160.85

115.12 118.76 121.40

100 110 120 130 140 150 160 170

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

Dry FGD - ACI at Absorber Inlet (1.5 lb/mmACF)

Wet FGD - ACI at ESP Inlet (5 lb/mmACF)

5 lb/mmBtu do not require ACI



## ACI ahead of the ESP raises the evaluated cost significantly for the wet FGD system, rendering dry FGD a low-cost

solution below 2 and 3 lb SO 2 

## /mmBtu fuel (operating at 0.8 lb/mmBtu PRB coal). However, if ACI has a major

impact on ESP performance, a COHPAV may be required. The sensitivity of adding COHPAC to wet FGD is

shown in Figure 3-5.

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## Figure 3-5. Impact of Mercury Control with ACI Ahead of

COHPAC Baghouse for Wet FGD to Meet Future Hg-MACT

136.82 142.83 149.52 160.85

115.12 118.76 121.40

100 110 120 130 140 150 160 170

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

Dry FGD - ACI at Absorber Inlet (1.5 lb/mmACF)

Wet FGD - ACI at COHPAC Inlet (1.5 lb/mmACF)

5 lb/mmBtu do not require ACI



## The differential between dry and wet FGD increases signi ficantly if wet FGD requires the additional baghouse,

rendering dry FGD even more economical.

3.5.4.5 Evaluate Impact of SCR - Related to Sulfuric Acid Control

The base dry and wet FGD system designs are based on the use of high-sulfur PRB coal. The dry system will have

an advantage over the wet system if the condensable em issions are further lowered from the existing level of

265 lb/hr (718 lb/hr total – 453 lb/hr filterable) or 0.03 lb /mmBtu. If all of the condensable emission is assumed to

be sulfuric acid, it will be equa l to approximately 10 ppmvd (@3% O 2 

## ). With the installation of either wet or dry

FGD for 2 lb SO 2 

## /mmBtu fuel, the sulfuric acid emission will be lo wer than the current allowable limit. However, a

wet FGD system designed for 2, 3 and 5 lb SO 2 

## /mmBtu will require an additional alkali injection system, whereas a

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## dry FGD system installed on 3 lb/mmBtu fuel will not require any additional alkali injection. It is assumed that if

SO 3 

## control is required, the emissions will have to be lowe red to similar levels as dry FGD, which could be lower

than 5 ppmvd (@3%O 2 

## ). The Trona requirement was estimated to achieve this level without any credit for SO 3



## capture by the wet FGD.

The injection of Trona required to control SO 3 

## eliminates the cost advantage of wet FGD over dry FGD up to 3 lb

SO 2 

## /mmBtu fuel. The results can be seen in Figure 3-6.

Figure 3-6. Impact of SO 3 

## Control with Trona Injection for

Future SCR Resulting in Increased Sulfuric Acid Emission

108.38 116.12 122.85 175.11

108.42 111.06 113.71

100 110 120 130 140 150 160 170 180

0123456

SO2, lb/mmBtuLevelized Cost, M$/yr Wet FGD

Dry FGD Des. SO2 lb/mmBtu 2.0 3.0 5.0

Oper. SO2 lb/mmBtu 0.8 0.8 5.0

2, 3, and 5 lb sulfur wet FGD will require SO3 control

with trona injection if fired with Bitumonous coal



# 3.6 SULFUR REDUCTION TECHNOLOGY CONCLUSIONS

The economic evaluation showed that a dry FGD system is cost-effective when the desi gn sulfur in the coal is

below 3 lb SO 2 

## /mmBtu and the unit is operated at or below 0.8 lb SO 2 

## /mmBtu, regardless of the possible

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## sensitivities associated with r eagent cost, PM 2.5, or mercury regulations. Dry FGD is the low-cost technology

through most of the sensitivities. Dry FGD becomes even more attractive below 3 lb/mmBtu fuel under the

following scenarios:

1. The capital cost can be reduced by 7% with the use of two modules in lieu of the three modules anticipated

in the base case design.

2. The Hg-MACT regulation requiring 90% reduction while burning PRB coal would give dry FGD a cost

advantage.

3. If the operating sulfur is lower than 1.2 lb/mmBtu , the dry FGD becomes cost-competitive with wet FGD

due to reduced operating cost for lime as a reagent.

SCR system and particulate emissions systems installations have no significant impact on the selection of

technology as long as current permit limits are maintained. The dry FGD system will have an advantage over the

wet FGD system if the condensable emission rate is furt her lowered from the existing level of 265 lb/hr (718 lb/hr

total – 453 lb/hr filterable) or 0.03 lb/mmBtu. If all the emi ssion is assumed to be sulfuric acid, it will be equal to

approximately 10 ppmvd (@ 3% O 2 

## ). With the installation of either FGD for 2 lb SO 2 

## /mmBtu fuel, the sulfuric acid

emission rate will be lower than the current allowable limit. The wet FGD system designed for bituminous coal

with 2, 3 and 5 lb/mmBtu will require an additional alka li injection system, whereas the dry FGD system installed

on 2 and 3 lb/mmBtu fuel will not require any add itional alkali injection. The impact of future SO 3 

## control almost

eliminates the cost advantage of wet FGD.

The wet FGD system will have an advantage over dry FGD in the case of CO 2 

## emission control as it is capable of

lowering the SO 2 

## concentration slightly better than the dry FGD. However, both systems will require some sort of

pre-scrubbing, which will result in somewhat higher operating cost for the CO 2 

## scrubbing installed on the dry FGD.

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# A PPENDIX 

# A

Dry FGD General Arrangement

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# A PPENDIX 

# B

Wet FGD General Arrangement

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# A PPENDIX 

# C

Dry FGD Capital Cost Estimate

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# A PPENDIX 

# D

Wet FGD Capital Cost Estimate

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# A PPENDIX 

# E

Financial Analysis SummaryWHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Economic Parameter InputsCaseLevelized(M$/year)Input AssumptionsSourceCase TechnologyTax Fuel Type$160.85Case Number Selection:51 Case 1 - Wet FGD 7-Year Amort. PRB Coal 1 113.78TechnologyCase 5 - Wet FGD 2 Case 2 - DryFGD 7-Year Amort. PRB Coal 2 111.06Tax Depreciation 7-Year Amort. 3 Case 3 - Wet FGD 7-Year Amort. PRB Coal 3 120.47Fuel Type PRB Coal 4 Case 4 - DryFGD 7-Year Amort. PRB Coal 4 113.715 Case 5 - Wet FGD 7-Year Amort. PRB Coal 5 160.85Basis for Fixed Charges RegulatedEvaluation Period(years)40Econ Parameters. 5-12-08Book Life - Regulated(years)40Econ Parameters. 5-12-08lb/mmBtu M$/yr M$/yrBase Year for ExpressingCosts 2008 Econ Parameters. 5-12-08wet dryCommercial OperatingDate 2013 Econ Parameters. 5-12-08Compliance Date 9/27/2013 Econ Parameters. 5-12-081 107.08 108.42Escalation Rates2 113.78 111.06Capital Costs(%/year)3.00% Email 5-15-083 120.47 113.71O&M Costs(%/year)2.00%Econ Parameters. 5-12-085 160.85PropertyTaxes(%/year)*3.00%Email 5-15-08PropertyTax Rate0.944%Econ Parameters. 5-12-08Insurance Rate0.000%Included in PropertyTaxTax Rate for Deferred Taxes37.275%Common EquityFraction0.5359Econ Parameters. 5-12-08Preferred Stock Fraction0.0444Econ Parameters. 5-12-08Debt Fraction0.4197Econ Parameters. 5-12-08Return on Common Equity9.90%Return on Preferred Stock5.99%Return on Debt6.34%* PropertyTaxes are applied to market valueFederal and State tax rate, %39.23%Econ Parameters. 5-12-08Before tax cost of money8.23%After tax cost of money7.19%Weighted AnnuityFactor 7.67%Total Capital Requirement 819,294,000Fixed Charge Rate ParametersInvestment Book Depreciation 20,482,350ITC Normalized -Preferred AFUDC Recovery-EquityAFUDC Recovery-Debt Book Depreciation 8,596,442Preferred Book Depreciation 909,416EquityBook Depreciation 10,976,491ResultsENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Case 1 - Wet FGD Case 2 - DryFGD Case 3 - Wet FGD Case 4 - DryFGD Case 5 - Wet2 lb/mmBtu 2 lb/mmBtu 3 lb/mmBtu 3 lb/mmBtu 5 lb/mmBtu1 2 3 45Input AssumptionsNet Plant Capacity(MW)1,688 1,688 1,688 1,688 1,688CapacityFactor(at In-Service Date)72.00% 72.00% 72.00% 72.00% 72.00%CF's tab. Email.(used onlyfor longterm average inyears 2039-2052)Equivalent AvailabilityFactor90.00% 90.00% 90.00% 90.00% 90.00%Aux Power(MW)28.00 22.80 32.60 23.60 40.40Aux Power(MWh/year at full load)245,280 199,728 285,576 206,736 353,904Email 5-15-08Construction Duration(months)48.0 48.0 48.0 48.0 48.0 PlaceholderTie-In Outage Duration(months)3.0 3.0 3.0 3.0 3.0 PlaceholderAmount in Excess of Normal Outage(mo1.5 1.5 1.5 1.5 1.5 PlaceholderBase Year2008 2008 2008 2008 2008In-Service Year2013 2013 2013 2013 2013Total Water Consumption(gpm)2,522 2,100 2,562 2,120 2,640Email 5-15-08Waste Disposal(lb/hr)45,138 35,652 45,138 35,652 289,070Email 5-15-08 22.569Lime Rate(tons/hr)0.0 8.4 0.0 8.4 0.0Email 5-15-08Limestone Rate(tons/hr)11.7 0.0 11.7 0.0 74.1Email 5-15-08Capital Investment CostsDirect & Indirect Costs483,486,000 458,871,000 504,276,000 470,802,000 531,835,000 Email 5-16-08Escalation 49,599,000 47,059,000 51,732,000 48,283,000 54,559,000 Email 5-16-08Contingency106,617,000 101,186,000 111,202,000 103,817,000 117,279,000 Email 5-16-08Taxes0 0 0 00Email 5-16-08AFUDC 105,110,000 99,781,000 109,630,000 102,375,000 115,621,000 Email 5-16-08Total Base-Year Value744,812,000 706,897,000 776,840,000 725,277,000 819,294,000Value at In-Service Date 744,812,000 706,897,000 776,840,000 725,277,000 819,294,000$/kW 441 419 460 430 485Fixed O&M(2008 $/year)OperatingLabor 1,773,000 1,351,000 1,773,000 1,351,000 1,773,000 Email 5-15-08Materials and Supplies 3,384,000 2,983,000 3,530,000 3,060,000 3,723,000 Email 5-15-08Maintenance Labor 2,256,000 1,989,000 2,353,000 2,040,000 2,482,000 Email 5-15-08Administrative Labor0 0 0 00Other0 0 0 00Total Base-Year Value7,413,000 6,323,000 7,656,000 6,451,000 7,978,000$/kW-year 4.39 3.75 4.54 3.82 4.73Variable O&M(2008 $)BagReplacement Cost 0 1,653,000 0 1,653,000 0Lime,$/ton$107.00$107.00$107.00$107.00$107.00Email 5-15-08Limestone,$/ton$38.00$38.00$38.00$38.00$38.00Email 5-15-08Total Water Requirement,$/1000gal$0.66$0.66$0.66$0.66$0.66Email 5-15-08BagCost,$/bag$110.00$110.00$110.00$110.00$110.00Waste Ash Disposal,$/ton$8.58$8.58$8.58$8.58$8.58Email 5-15-08Technology Base Year Cost andPerformance InputsENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB CoalCalendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027OperatingYear12 3 4 5 6 7 8 9 10 11 12 13 14 15Annual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fuel Prices ($/mmBtu)PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 3.27 3.35 3.39 3.47Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1.4241 1.4562 1.4889 1.5224Variable O&M CalculationsConsumption RatesLime(tons)000000000000000Limestone(tons)76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788Total Water Requirement(1000sga 986,988 976,576 1,017,281 1,018,738 952,938 955,961 853,928 882,096 917,876 986,988 976,576 1,017,281 1,018,738 952,938 955,961Waste Ash Disposal(tons)147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 152.38 155.81 159.32 162.90Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 52.17 53.21 54.27 55.36BagCost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 151.01 154.03 157.11 160.25Total Water Requirement, $/1000gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 11.77 12.01 12.25 12.49Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9.47% 9.33% 9.20% 9.06%O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1.4002 1.4282 1.4568 1.4859CapacityFactor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12%Annual Generation(MWh)11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901Aux. Power(MWh)182,631 180,704 188,236 188,506 176,330 176,889 158,009 163,222 169,842 182,631 180,704 188,236 188,506 176,330 176,889Aux. Power Cost($/MWh)66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 105.74 109.20 111.66 114.17Fuel Price($/mmBtu)2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3.2710 3.3498 3.3946 3.4689Fuel Consumption(mmBtu/year)000000000000000Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0.4347 0.4056 0.3784 0.3530Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00Annual Revenue Requirements:Expense TotalsFixed Charges Basis 113,758,949 108,569,447 102,748,573 96,935,254 91,129,718 85,332,198 79,542,935 75,469,428 73,750,163 72,678,449 71,616,029 70,563,179 69,520,189 68,487,352 67,464,975Fixed O&M 8,348,242 8,515,207 8,685,511 8,859,221 9,036,406 9,217,134 9,401,476 9,589,506 9,781,296 9,976,922 10,176,460 10,379,990 10,587,589 10,799,341 11,015,328Fuel000000000000000Aux Power Purchase 12,053,370 11,731,254 12,161,351 12,718,126 12,133,421 13,455,728 13,287,300 15,173,294 16,305,449 18,106,946 18,502,24119,904,149 20,584,956 19,688,619 20,195,476Bag Replacement000000000000000Lime000000000000000Limestone 3,196,265 3,225,800 3,427,458 3,501,015 3,340,382 3,417,998 3,114,248 3,281,316 3,482,703 3,819,833 3,855,129 4,096,130 4,184,037 3,992,066 4,084,824Total Water Requirement 726,291 734,798 782,647 801,403 766,507 786,240 718,124 758,504 807,029 887,320 897,714 956,172 979,086 936,453 960,561Waste Ash Disposal 1,393,942 1,406,823 1,494,769 1,526,848 1,456,794 1,490,643 1,358,173 1,431,034 1,518,862 1,665,890 1,681,283 1,786,387 1,824,725 1,741,003 1,781,457Total Revenue Requirements 139,477,059 134,183,329 129,300,310 124,341,867 117,863,228 113,699,941 107,422,257 105,703,082 105,645,503 107,135,360 106,728,857 107,686,007 107,680,582 105,644,835 105,502,622Busbar ElectricityPrice($/MWh)12.67 12.32 11.39 10.94 11.09 10.66 11.28 10.74 10.32 9.73 9.80 9.49 9.48 9.94 9.89Levelized($/MWh)10.64Present Value(PVRR)130,123,123 116,789,005 104,991,625 94,194,203 83,298,431 74,967,052 66,077,889 60,659,836 56,560,898 53,511,831 49,733,673 46,814,420 43,672,642 39,973,488 37,242,491Cumulative PVRR 130,123,123 246,912,128 351,903,754 446,097,957 529,396,388 604,363,440 670,441,329 731,101,165 787,662,063 841,173,894 890,907,568 937,721,988 981,394,631 1,021,368,118 1,058,610,609Net Present Value = 1,484,233,596Levelized ($/year) 113,775,9154.95 $/kW-yr fixed1.58 $/MWH variableENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.64Present Value(PVRR)Cumulative PVRRNet Present Value = 1,484,233,596Levelized ($/year) 113,775,9152028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 204216 17 18 19 20 21 22 23 24 25 26 27 28 29 300.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 4.32 4.38 4.44 4.541.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1.9884 2.0331 2.0789 2.125600000000000000065,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 73,668 73,668 73,668 73,668853,928 882,096 917,876 986,988 976,576 1,017,281 1,018,738 952,938 955,961 853,928 882,096 954,406 954,406 954,406 954,406127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 142,348 142,348 142,348 142,348166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 212.76 217.54 222.44 227.4456.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 70.21 71.61 73.04 74.51163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 203.23 207.30 211.45 215.671.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 1.31 1.34 1.37 1.4012.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 15.85 16.16 16.49 16.820.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7.54% 7.42% 7.31% 7.20%1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1.8845 1.9222 1.9607 1.999964.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72.00% 72.00% 72.00% 72.00%9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646,554 10,646,554 10,646,554 10,646,554158,009 163,222 169,842 182,631 180,704 188,236 188,506 176,330 176,889 158,009 163,222 176,602 176,602 176,602 176,602116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 149.11 152.47 155.90 159.413.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4.3249 4.3830 4.4423 4.54220000000000000000.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0.1535 0.1432 0.1336 0.12461.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0066,453,371 65,452,863 64,463,784 63,486,476 62,521,294 61,568,600 60,628,770 59,702,188 58,789,254 57,890,376 57,005,975 56,136,487 55,282,358 54,444,050 53,622,03611,235,635 11,460,347 11,689,554 11,923,345 12,161,812 12,405,048 12,653,149 12,906,212 13,164,337 13,427,623 13,696,176 13,970,099 14,249,501 14,534,491 14,825,18100000000000000018,445,845 19,483,034 20,729,466 22,791,829 23,058,813 24,560,366 25,148,946 24,053,878 24,673,113 22,535,563 23,802,712 26,333,393 26,925,894 27,531,727 28,151,1910000000000000000000000000000003,721,814 3,921,476 4,162,152 4,565,054 4,607,236 4,895,254 5,000,311 4,770,888 4,881,743 4,447,913 4,686,527 5,172,117 5,275,560 5,381,071 5,488,692877,343 926,675 985,960 1,084,052 1,096,751 1,168,169 1,196,164 1,144,079 1,173,532 1,071,863 1,132,133 1,252,500 1,280,681 1,309,497 1,338,9601,623,143 1,710,218 1,815,181 1,990,893 2,009,289 2,134,898 2,180,716 2,080,660 2,129,006 1,939,806 2,043,869 2,255,643 2,300,756 2,346,771 2,393,706102,357,151 102,954,614 103,846,097 105,841,649 105,455,195 106,732,336 106,808,056 104,657,906 104,810,984 101,313,144 102,367,392 105,120,240 105,314,751 105,547,607 105,819,76710.75 10.46 10.14 9.61 9.68 9.41 9.40 9.85 9.83 10.64 10.40 9.87 9.89 9.91 9.9433,708,960 31,631,857 29,766,018 28,303,416 26,308,855 24,841,721 23,192,169 21,201,232 19,808,316 17,863,158 16,838,593 16,131,776 15,077,757 14,097,680 13,186,1421,092,319,570 1,123,951,426 1,153,717,445 1,182,020,861 1,208,329,716 1,233,171,437 1,256,363,606 1,277,564,838 1,297,373,154 1,315,236,312 1,332,074,905 1,348,206,681 1,363,284,438 1,377,382,118 1,390,568,260ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-1: Annual Revenue Requirements - Case 1Case 1 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.64Present Value(PVRR)Cumulative PVRRNet Present Value = 1,484,233,596Levelized ($/year) 113,775,9152043 2044 2045 2046 2047 2048 2049 2050 2051 205231 32 33 34 35 36 37 38 39 400.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.672.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.6554000000000073,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406 954,406142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.1276.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.911.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.7517.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.500.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.437972.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602 176,602162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.674200000000000.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.06221.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0052,816,807 52,028,864 51,258,728 50,506,931 49,774,025 49,060,576 48,367,167 47,694,401 47,042,895 46,413,28915,121,685 15,424,119 15,732,601 16,047,253 16,368,198 16,695,562 17,029,473 17,370,063 17,717,464 18,071,813000000000028,784,593 29,432,246 30,094,472 30,771,597 31,463,958 32,171,897 32,895,765 33,635,920 34,392,728 35,166,564000000000000000000005,598,466 5,710,435 5,824,644 5,941,137 6,059,960 6,181,159 6,304,782 6,430,878 6,559,495 6,690,6851,369,087 1,399,891 1,431,389 1,463,595 1,496,526 1,530,198 1,564,627 1,599,832 1,635,828 1,672,6342,441,580 2,490,412 2,540,220 2,591,025 2,642,845 2,695,702 2,749,616 2,804,608 2,860,700 2,917,914106,132,218 106,485,968 106,882,054 107,321,538 107,805,512 108,335,094 108,911,431 109,535,701 110,209,111 110,932,9009.97 10.00 10.04 10.08 10.13 10.18 10.23 10.29 10.35 10.4212,338,145 11,549,062 10,814,609 10,130,821 9,494,026 8,900,826 8,348,074 7,832,857 7,352,478 6,904,4371,402,906,405 1,414,455,468 1,425,270,077 1,435,400,897 1,444,894,923 1,453,795,749 1,462,143,823 1,469,976,680 1,477,329,158 1,484,233,596ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB CoalCalendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027OperatingYear12 3 4 5 6 7 8 9 10 11 12 13 14 15Annual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fuel Prices ($/mmBtu)PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 3.27 3.35 3.39 3.47Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1.4241 1.4562 1.4889 1.5224Variable O&M CalculationsConsumption RatesLime(tons)54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124Limestone(tons)000000000000000Total Water Requirement(1000sga 821,838 813,168 847,062 848,275 793,485 796,002 711,042 734,497 764,290 821,838 813,168 847,062 848,275 793,485 796,002Waste Ash Disposal(tons)116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 152.38 155.81 159.32 162.90Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 52.17 53.21 54.27 55.36BagCost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 151.01 154.03 157.11 160.25Total Water Requirement, $/1000gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 11.77 12.01 12.25 12.49Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9.47% 9.33% 9.20% 9.06%O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1.4002 1.4282 1.4568 1.4859CapacityFactor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12%Annual Generation(MWh)11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901Aux. Power(MWh)148,713 147,145 153,278 153,497 143,583 144,038 128,665 132,909 138,300 148,713 147,145 153,278 153,497 143,583 144,038Aux. Power Cost($/MWh)66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 105.74 109.20 111.66 114.17Fuel Price($/mmBtu)2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3.2710 3.3498 3.3946 3.4689Fuel Consumption(mmBtu/year)000000000000000Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0.4347 0.4056 0.3784 0.3530Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00Annual Revenue Requirements:Expense TotalsFixed Charges Basis 107,967,997 103,042,669 97,518,109 92,000,720 86,490,718 80,988,323 75,493,765 71,627,622 69,995,877 68,978,719 67,970,381 66,971,128 65,981,231 65,000,972 64,030,639Fixed O&M 7,120,725 7,263,139 7,408,402 7,556,570 7,707,702 7,861,856 8,019,093 8,179,475 8,343,064 8,509,926 8,680,124 8,853,726 9,030,801 9,211,417 9,395,645Fuel000000000000000Aux Power Purchase 9,814,887 9,552,593 9,902,815 10,356,188 9,880,071 10,956,807 10,819,659 12,355,396 13,277,294 14,744,227 15,066,111 16,207,664 16,762,035 16,032,161 16,444,887Bag Replacement 1,861,546 1,878,748 1,996,196 2,039,037 1,945,482 1,990,687 1,813,779 1,911,081 2,028,372 2,224,720 2,245,278 2,385,639 2,436,838 2,325,031 2,379,055Lime 6,543,322 6,619,971 7,051,053 7,220,029 6,905,645 7,083,421 6,469,751 6,833,537 7,270,715 7,994,074 8,087,716 8,614,376 8,820,816 8,436,729 8,653,921Limestone000000000000000Total Water Requirement 604,762 611,846 651,689 667,306 638,250 654,681 597,962 631,585 671,991 738,847 747,502 796,178 815,258 779,759 799,833Waste Ash Disposal 1,100,988 1,111,161 1,180,625 1,205,962 1,150,630 1,177,366 1,072,736 1,130,284 1,199,654 1,315,782 1,327,941 1,410,956 1,441,236 1,375,110 1,407,061Total Revenue Requirements 135,014,228 130,080,128 125,708,889 121,045,812 114,718,497 110,713,140 104,286,744 102,668,981 102,786,967 104,506,296 104,125,053 105,239,667 105,288,216 103,161,178 103,111,043Busbar ElectricityPrice($/MWh)12.26 11.94 11.08 10.65 10.79 10.38 10.95 10.43 10.04 9.49 9.56 9.27 9.26 9.70 9.67Levelized($/MWh)10.39Present Value(PVRR)125,959,589 113,217,706 102,075,398 91,697,303 81,075,930 72,997,731 64,149,163 58,918,657 55,030,484 52,198,670 48,520,349 45,750,921 42,702,356 39,033,731 36,398,262Cumulative PVRR 125,959,589 239,177,295 341,252,693 432,949,995 514,025,926 587,023,656 651,172,819 710,091,476 765,121,960 817,320,630 865,840,979 911,591,900 954,294,257 993,327,988 1,029,726,250Net Present Value = 1,448,851,893Levelized ($/year) 111,063,6834.22 $/kW-yr fixed1.81 $/MWH variableENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.39Present Value(PVRR)Cumulative PVRRNet Present Value = 1,448,851,893Levelized ($/year) 111,063,6832028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 204216 17 18 19 20 21 22 23 24 25 26 27 28 29 300.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 4.32 4.38 4.44 4.541.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1.9884 2.0331 2.0789 2.125647,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 53,037 53,037 53,037 53,037000000000000000711,042 734,497 764,290 821,838 813,168 847,062 848,275 793,485 796,002 711,042 734,497 794,707 794,707 794,707 794,707100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 112,432 112,432 112,432 112,432166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 212.76 217.54 222.44 227.4456.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 70.21 71.61 73.04 74.51163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 203.23 207.30 211.45 215.671.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 1.31 1.34 1.37 1.4012.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 15.85 16.16 16.49 16.820.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7.54% 7.42% 7.31% 7.20%1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1.8845 1.9222 1.9607 1.999964.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72.00% 72.00% 72.00% 72.00%9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646,554 10,646,554 10,646,554 10,646,554128,665 132,909 138,300 148,713 147,145 153,278 153,497 143,583 144,038 128,665 132,909 143,804 143,804 143,804 143,804116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 149.11 152.47 155.90 159.413.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4.3249 4.3830 4.4423 4.54220000000000000000.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0.1535 0.1432 0.1336 0.12461.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0063,070,531 62,120,955 61,182,225 60,254,668 59,338,618 58,434,422 57,542,434 56,663,021 55,796,560 54,943,439 54,104,060 53,278,833 52,468,184 51,672,550 50,892,3829,583,558 9,775,229 9,970,734 10,170,149 10,373,552 10,581,023 10,792,643 11,008,496 11,228,666 11,453,239 11,682,304 11,915,950 12,154,26912,397,355 12,645,30200000000000000015,020,188 15,864,756 16,879,708 18,559,061 18,776,462 19,999,155 20,478,427 19,586,729 20,090,963 18,350,387 19,382,208 21,442,906 21,925,371 22,418,692 22,923,1132,167,633 2,283,919 2,424,092 2,658,747 2,683,315 2,851,060 2,912,247 2,778,627 2,843,191 2,590,522 2,729,495 3,012,309 3,072,555 3,134,006 3,196,6867,904,190 8,348,634 8,882,740 9,766,479 9,880,883 10,524,311 10,776,522 10,307,276 10,572,624 9,656,667 10,199,650 11,284,067 11,537,958 11,797,562 12,063,008000000000000000730,540 771,617 820,981 902,660 913,234 972,702 996,013 952,643 977,168 892,511 942,696 1,042,922 1,066,388 1,090,382 1,114,9151,282,019 1,350,794 1,433,698 1,572,482 1,587,012 1,686,223 1,722,411 1,643,383 1,681,569 1,532,131 1,614,324 1,781,591 1,817,223 1,853,567 1,890,63999,758,660 100,515,905 101,594,178 103,884,245 103,553,076 105,048,896 105,220,697 102,940,176 103,190,740 99,418,897 100,654,737 103,758,578 104,041,949 104,364,115 104,726,04410.47 10.22 9.92 9.44 9.51 9.26 9.26 9.68 9.68 10.44 10.23 9.75 9.77 9.80 9.8432,853,208 30,882,586 29,120,538 27,779,981 25,834,316 24,449,904 22,847,492 20,853,260 19,502,105 17,529,172 16,556,875 15,922,815 14,895,532 13,939,604 13,049,8541,062,579,458 1,093,462,043 1,122,582,581 1,150,362,562 1,176,196,878 1,200,646,782 1,223,494,274 1,244,347,534 1,263,849,639 1,281,378,810 1,297,935,685 1,313,858,501 1,328,754,033 1,342,693,637 1,355,743,491ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-2: Annual Revenue Requirements - Case 2Case 2 - Dry FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.39Present Value(PVRR)Cumulative PVRRNet Present Value = 1,448,851,893Levelized ($/year) 111,063,6832043 2044 2045 2046 2047 2048 2049 2050 2051 205231 32 33 34 35 36 37 38 39 400.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.672.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.655453,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,0370000000000794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707 794,707112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.1276.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.911.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.7517.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.500.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.437972.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804 143,804162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.674200000000000.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.06221.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0050,128,143 49,380,311 48,649,378 47,935,852 47,240,255 46,563,125 45,905,014 45,266,495 44,648,155 44,050,59912,898,208 13,156,172 13,419,295 13,687,681 13,961,435 14,240,663 14,525,477 14,815,986 15,112,306 15,414,552000000000023,438,883 23,966,257 24,505,498 25,056,872 25,620,652 26,197,116 26,786,551 27,389,249 28,005,507 28,635,6313,260,620 3,325,832 3,392,349 3,460,196 3,529,400 3,599,988 3,671,987 3,745,427 3,820,336 3,896,74212,334,425 12,611,950 12,895,719 13,185,872 13,482,555 13,785,912 14,096,095 14,413,257 14,737,555 15,069,15000000000001,140,001 1,165,651 1,191,878 1,218,696 1,246,116 1,274,154 1,302,822 1,332,136 1,362,109 1,392,7561,928,452 1,967,021 2,006,361 2,046,488 2,087,418 2,129,166 2,171,750 2,215,185 2,259,488 2,304,678105,128,731 105,573,194 106,060,479 106,591,658 107,167,830 107,790,124 108,459,697 109,177,735 109,945,456 110,764,1099.87 9.92 9.96 10.01 10.07 10.12 10.19 10.25 10.33 10.4012,221,487 11,450,066 10,731,480 10,061,922 9,437,867 8,856,051 8,313,449 7,807,259 7,334,888 6,893,9321,367,964,978 1,379,415,044 1,390,146,525 1,400,208,447 1,409,646,314 1,418,502,365 1,426,815,814 1,434,623,073 1,441,957,962 1,448,851,893ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB CoalCalendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027OperatingYear12 3 4 5 6 7 8 9 10 11 12 13 14 15Annual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fuel Prices ($/mmBtu)PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 3.27 3.35 3.39 3.47Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1.4241 1.4562 1.4889 1.5224Variable O&M CalculationsConsumption RatesLime(tons)000000000000000Limestone(tons)76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788Total Water Requirement(1000sga 1,002,642 992,065 1,033,415 1,034,896 968,052 971,123 867,471 896,086 932,434 1,002,642 992,065 1,033,415 1,034,896 968,052 971,123Waste Ash Disposal(tons)147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 152.38 155.81 159.32 162.90Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 52.17 53.21 54.27 55.36BagCost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 151.01 154.03 157.11 160.25Total Water Requirement, $/1000gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 11.77 12.01 12.25 12.49Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9.47% 9.33% 9.20% 9.06%O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1.4002 1.4282 1.4568 1.4859CapacityFactor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12%Annual Generation(MWh)11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901Aux. Power(MWh)212,634 210,391 219,160 219,474 205,298 205,950 183,968 190,037 197,745 212,634 210,391 219,160 219,474 205,298 205,950Aux. Power Cost($/MWh)66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 105.74 109.20 111.66 114.17Fuel Price($/mmBtu)2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3.2710 3.3498 3.3946 3.4689Fuel Consumption(mmBtu/year)000000000000000Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0.4347 0.4056 0.3784 0.3530Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00Annual Revenue Requirements:Expense TotalsFixed Charges Basis 118,650,750 113,238,091 107,166,911 101,103,611 95,048,429 89,001,607 82,963,397 78,714,723 76,921,527 75,803,729 74,695,622 73,597,499 72,509,658 71,432,408 70,366,067Fixed O&M 8,621,899 8,794,337 8,970,224 9,149,629 9,332,621 9,519,274 9,709,659 9,903,852 10,101,929 10,303,968 10,510,047 10,720,248 10,934,653 11,153,346 11,376,413Fuel000000000000000Aux Power Purchase 14,033,566 13,658,532 14,159,288 14,807,532 14,126,768 15,666,312 15,470,214 17,666,049 18,984,202 21,081,658 21,541,89523,174,116 23,966,770 22,923,177 23,513,304Bag Replacement000000000000000Lime000000000000000Limestone 3,196,265 3,225,800 3,427,458 3,501,015 3,340,382 3,417,998 3,114,248 3,281,316 3,482,703 3,819,833 3,855,129 4,096,130 4,184,037 3,992,066 4,084,824Total Water Requirement 737,810 746,453 795,060 814,114 778,665 798,710 729,514 770,534 819,829 901,393 911,952 971,337 994,615 951,306 975,796Waste Ash Disposal 1,393,942 1,406,823 1,494,769 1,526,848 1,456,794 1,490,643 1,358,173 1,431,034 1,518,862 1,665,890 1,681,283 1,786,387 1,824,725 1,741,003 1,781,457Total Revenue Requirements 146,634,232 141,070,036 136,013,711 130,902,749 124,083,659 119,894,544 113,345,205 111,767,509 111,829,053 113,576,471 113,195,930 114,345,717 114,414,458 112,193,307 112,097,862Busbar ElectricityPrice($/MWh)13.32 12.95 11.99 11.52 11.67 11.24 11.90 11.36 10.92 10.32 10.39 10.08 10.07 10.55 10.51Levelized($/MWh)11.27Present Value(PVRR)136,800,306 122,782,981 110,442,895 99,164,348 87,694,646 79,051,408 69,721,230 64,140,030 59,871,471 56,729,029 52,747,210 49,709,601 46,403,740 42,451,274 39,570,615Cumulative PVRR 136,800,306 259,583,287 370,026,182 469,190,529 556,885,176 635,936,584 705,657,814 769,797,843 829,669,314 886,398,343 939,145,553 988,855,154 1,035,258,894 1,077,710,168 1,117,280,783Net Present Value = 1,571,524,323Levelized ($/year) 120,467,3035.11 $/kW-yr fixed1.76 $/MWH variableENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)11.27Present Value(PVRR)Cumulative PVRRNet Present Value = 1,571,524,323Levelized ($/year) 120,467,3032028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 204216 17 18 19 20 21 22 23 24 25 26 27 28 29 300.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 4.32 4.38 4.44 4.541.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1.9884 2.0331 2.0789 2.125600000000000000065,912 68,087 70,848 76,183 75,379 78,521 78,634 73,555 73,788 65,912 68,087 73,668 73,668 73,668 73,668867,471 896,086 932,434 1,002,642 992,065 1,033,415 1,034,896 968,052 971,123 867,471 896,086 969,543 969,543 969,543 969,543127,362 131,564 136,900 147,208 145,655 151,726 151,944 142,130 142,580 127,362 131,564 142,348 142,348 142,348 142,348166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 212.76 217.54 222.44 227.4456.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 70.21 71.61 73.04 74.51163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 203.23 207.30 211.45 215.671.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 1.31 1.34 1.37 1.4012.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 15.85 16.16 16.49 16.820.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7.54% 7.42% 7.31% 7.20%1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1.8845 1.9222 1.9607 1.999964.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72.00% 72.00% 72.00% 72.00%9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646,554 10,646,554 10,646,554 10,646,554183,968 190,037 197,745 212,634 210,391 219,160 219,474 205,298 205,950 183,968 190,037 205,615 205,615 205,615 205,615116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 149.11 152.47 155.90 159.413.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4.3249 4.3830 4.4423 4.54220000000000000000.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0.1535 0.1432 0.1336 0.12461.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0069,310,963 68,267,431 67,235,820 66,216,487 65,209,800 64,216,139 63,235,895 62,269,469 61,317,277 60,379,746 59,457,315 58,550,438 57,659,580 56,785,223 55,927,86211,603,942 11,836,020 12,072,741 12,314,196 12,560,479 12,811,689 13,067,923 13,329,281 13,595,867 13,867,784 14,145,140 14,428,043 14,716,604 15,010,936 15,311,15400000000000000021,476,234 22,683,818 24,135,021 26,536,201 26,847,046 28,595,283 29,280,558 28,005,586 28,726,553 26,237,834 27,713,157 30,659,593 31,349,434 32,054,797 32,776,0290000000000000000000000000000003,721,814 3,921,476 4,162,152 4,565,054 4,607,236 4,895,254 5,000,311 4,770,888 4,881,743 4,447,913 4,686,527 5,172,117 5,275,560 5,381,071 5,488,692891,258 941,373 1,001,597 1,101,246 1,114,146 1,186,697 1,215,136 1,162,225 1,192,145 1,088,863 1,150,089 1,272,365 1,300,994 1,330,266 1,360,1971,623,143 1,710,218 1,815,181 1,990,893 2,009,289 2,134,898 2,180,716 2,080,660 2,129,006 1,939,806 2,043,869 2,255,643 2,300,756 2,346,771 2,393,706108,627,354 109,360,337 110,422,513 112,724,075 112,347,997 113,839,961 113,980,539 111,618,110 111,842,591 107,961,946 109,196,098 112,338,199 112,602,927 112,909,063 113,257,64111.40 11.11 10.78 10.24 10.31 10.03 10.03 10.50 10.49 11.33 11.10 10.55 10.58 10.61 10.6435,773,907 33,599,956 31,651,055 30,143,866 28,028,464 26,496,005 24,749,593 22,611,206 21,137,225 19,035,450 17,961,858 17,239,446 16,121,195 15,080,927 14,112,9711,153,054,690 1,186,654,646 1,218,305,701 1,248,449,566 1,276,478,030 1,302,974,035 1,327,723,629 1,350,334,834 1,371,472,059 1,390,507,510 1,408,469,368 1,425,708,815 1,441,830,009 1,456,910,937 1,471,023,908ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-3: Annual Revenue Requirements - Case 3Case 3 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)11.27Present Value(PVRR)Cumulative PVRRNet Present Value = 1,571,524,323Levelized ($/year) 120,467,3032043 2044 2045 2046 2047 2048 2049 2050 2051 205231 32 33 34 35 36 37 38 39 400.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.672.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.6554000000000073,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668 73,668969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543 969,543142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348 142,348232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.1276.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.911.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.7517.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.500.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.437972.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615 205,615162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.674200000000000.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.06221.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0055,088,006 54,266,181 53,462,928 52,678,803 51,914,381 51,170,252 50,447,026 49,745,329 49,065,808 48,409,12815,617,378 15,929,725 16,248,320 16,573,286 16,904,752 17,242,847 17,587,704 17,939,458 18,298,247 18,664,212000000000033,513,490 34,267,544 35,038,563 35,826,931 36,633,037 37,457,280 38,300,069 39,161,821 40,042,962 40,943,928000000000000000000005,598,466 5,710,435 5,824,644 5,941,137 6,059,960 6,181,159 6,304,782 6,430,878 6,559,495 6,690,6851,390,801 1,422,094 1,454,091 1,486,809 1,520,262 1,554,468 1,589,443 1,625,206 1,661,773 1,699,1632,441,580 2,490,412 2,540,220 2,591,025 2,642,845 2,695,702 2,749,616 2,804,608 2,860,700 2,917,914113,649,722 114,086,391 114,568,766 115,097,990 115,675,236 116,301,708 116,978,640 117,707,300 118,488,985 119,325,03110.67 10.72 10.76 10.81 10.87 10.92 10.99 11.06 11.13 11.2113,212,075 12,373,375 11,592,371 10,864,894 10,187,083 9,555,364 8,966,427 8,417,205 7,904,860 7,426,7621,484,235,983 1,496,609,358 1,508,201,729 1,519,066,623 1,529,253,705 1,538,809,069 1,547,775,496 1,556,192,701 1,564,097,562 1,571,524,323ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB CoalCalendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027OperatingYear12 3 4 5 6 7 8 9 10 11 12 13 14 15Annual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fuel Prices ($/mmBtu)PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 3.27 3.35 3.39 3.47Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1.4241 1.4562 1.4889 1.5224Variable O&M CalculationsConsumption RatesLime(tons)54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124Limestone(tons)000000000000000Total Water Requirement(1000sga 829,489 820,739 854,948 856,173 800,873 803,413 717,662 741,336 771,406 829,489 820,739 854,948 856,173 800,873 803,413Waste Ash Disposal(tons)116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 152.38 155.81 159.32 162.90Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 52.17 53.21 54.27 55.36BagCost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 151.01 154.03 157.11 160.25Total Water Requirement, $/1000gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 11.77 12.01 12.25 12.49Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9.47% 9.33% 9.20% 9.06%O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1.4002 1.4282 1.4568 1.4859CapacityFactor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12%Annual Generation(MWh)11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901Aux. Power(MWh)153,931 152,308 158,656 158,883 148,621 149,092 133,179 137,572 143,153 153,931 152,308 158,656 158,883 148,621 149,092Aux. Power Cost($/MWh)66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 105.74 109.20 111.66 114.17Fuel Price($/mmBtu)2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3.2710 3.3498 3.3946 3.4689Fuel Consumption(mmBtu/year)000000000000000Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0.4347 0.4056 0.3784 0.3530Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00Annual Revenue Requirements:Expense TotalsFixed Charges Basis 110,775,269 105,721,877 100,053,673 94,392,827 88,739,559 83,094,097 77,456,675 73,490,009 71,815,837 70,772,232 69,737,677 68,712,441 67,696,806 66,691,060 65,695,498Fixed O&M 7,264,874 7,410,171 7,558,375 7,709,542 7,863,733 8,021,008 8,181,428 8,345,056 8,511,958 8,682,197 8,855,841 9,032,957 9,213,617 9,397,889 9,585,847Fuel000000000000000Aux Power Purchase 10,159,269 9,887,772 10,250,282 10,719,563 10,226,740 11,341,256 11,199,296 12,788,919 13,743,164 15,261,569 15,594,746 16,776,354 17,350,177 16,594,693 17,021,901Bag Replacement 1,861,546 1,878,748 1,996,196 2,039,037 1,945,482 1,990,687 1,813,779 1,911,081 2,028,372 2,224,720 2,245,278 2,385,639 2,436,838 2,325,031 2,379,055Lime 6,543,322 6,619,971 7,051,053 7,220,029 6,905,645 7,083,421 6,469,751 6,833,537 7,270,715 7,994,074 8,087,716 8,614,376 8,820,816 8,436,729 8,653,921Limestone000000000000000Total Water Requirement 610,393 617,543 657,756 673,519 644,192 660,776 603,530 637,466 678,248 745,726 754,461 803,591 822,849 787,019 807,280Waste Ash Disposal 1,100,988 1,111,161 1,180,625 1,205,962 1,150,630 1,177,366 1,072,736 1,130,284 1,199,654 1,315,782 1,327,941 1,410,956 1,441,236 1,375,110 1,407,061Total Revenue Requirements 138,315,660 133,247,243 128,747,960 123,960,479 117,475,982 113,368,611 106,797,194 105,136,353 105,247,947 106,996,300 106,603,660 107,736,314 107,782,339 105,607,530 105,550,562Busbar ElectricityPrice($/MWh)12.56 12.23 11.35 10.91 11.05 10.63 11.21 10.68 10.28 9.72 9.79 9.49 9.48 9.93 9.90Levelized($/MWh)10.64Present Value(PVRR)129,039,613 115,974,265 104,543,119 93,905,286 83,024,749 74,748,592 65,693,398 60,334,607 56,348,053 53,442,374 49,675,334 46,836,291 43,713,912 39,959,372 37,259,414Cumulative PVRR 129,039,613 245,013,878 349,556,997 443,462,282 526,487,032 601,235,623 666,929,022 727,263,629 783,611,682 837,054,056 886,729,390 933,565,681 977,279,593 1,017,238,965 1,054,498,380Net Present Value = 1,483,331,874Levelized ($/year) 113,706,7924.30 $/kW-yr fixed1.84 $/MWH variableENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.64Present Value(PVRR)Cumulative PVRRNet Present Value = 1,483,331,874Levelized ($/year) 113,706,7922028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 204216 17 18 19 20 21 22 23 24 25 26 27 28 29 300.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 4.32 4.38 4.44 4.541.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1.9884 2.0331 2.0789 2.125647,454 49,019 51,007 54,848 54,269 56,531 56,612 52,956 53,124 47,454 49,019 53,037 53,037 53,037 53,037000000000000000717,662 741,336 771,406 829,489 820,739 854,948 856,173 800,873 803,413 717,662 741,336 802,106 802,106 802,106 802,106100,596 103,914 108,129 116,270 115,044 119,839 120,011 112,259 112,615 100,596 103,914 112,432 112,432 112,432 112,432166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 212.76 217.54 222.44 227.4456.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 70.21 71.61 73.04 74.51163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 203.23 207.30 211.45 215.671.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 1.31 1.34 1.37 1.4012.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 15.85 16.16 16.49 16.820.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7.54% 7.42% 7.31% 7.20%1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1.8845 1.9222 1.9607 1.999964.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72.00% 72.00% 72.00% 72.00%9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646,554 10,646,554 10,646,554 10,646,554133,179 137,572 143,153 153,931 152,308 158,656 158,883 148,621 149,092 133,179 137,572 148,850 148,850 148,850 148,850116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 149.11 152.47 155.90 159.413.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4.3249 4.3830 4.4423 4.54220000000000000000.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0.1535 0.1432 0.1336 0.12461.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0064,710,426 63,736,159 62,773,021 61,821,347 60,881,479 59,953,773 59,038,592 58,136,314 57,247,324 56,372,021 55,510,817 54,664,134 53,832,407 53,016,086 52,215,6339,777,564 9,973,115 10,172,577 10,376,029 10,583,549 10,795,220 11,011,125 11,231,347 11,455,974 11,685,094 11,918,795 12,157,171 12,400,315 12,648,321 12,901,28800000000000000015,547,212 16,421,414 17,471,979 19,210,256 19,435,285 20,700,880 21,196,969 20,273,983 20,795,909 18,994,260 20,062,286 22,195,288 22,694,682 23,205,313 23,727,4322,167,633 2,283,919 2,424,092 2,658,747 2,683,315 2,851,060 2,912,247 2,778,627 2,843,191 2,590,522 2,729,495 3,012,309 3,072,555 3,134,006 3,196,6867,904,190 8,348,634 8,882,740 9,766,479 9,880,883 10,524,311 10,776,522 10,307,276 10,572,624 9,656,667 10,199,650 11,284,067 11,537,958 11,797,562 12,063,008000000000000000737,341 778,801 828,625 911,065 921,737 981,759 1,005,286 961,513 986,266 900,821 951,473 1,052,633 1,076,317 1,100,534 1,125,2961,282,019 1,350,794 1,433,698 1,572,482 1,587,012 1,686,223 1,722,411 1,643,383 1,681,569 1,532,131 1,614,324 1,781,591 1,817,223 1,853,567 1,890,639102,126,385 102,892,837 103,986,732 106,316,403 105,973,260 107,493,225 107,663,151 105,332,444 105,582,856 101,731,516 102,986,840 106,147,193 106,431,458 106,755,390 107,119,98110.72 10.46 10.16 9.66 9.73 9.47 9.47 9.91 9.90 10.68 10.47 9.97 10.00 10.03 10.0633,632,963 31,612,876 29,806,329 28,430,372 26,438,101 25,018,816 23,377,843 21,337,877 19,954,193 17,936,924 16,940,487 16,289,373 15,237,635 14,259,000 13,348,1611,088,131,343 1,119,744,219 1,149,550,548 1,177,980,920 1,204,419,021 1,229,437,837 1,252,815,681 1,274,153,558 1,294,107,751 1,312,044,675 1,328,985,162 1,345,274,534 1,360,512,169 1,374,771,169 1,388,119,330ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-4: Annual Revenue Requirements - Case 4Case 4 - Dry FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)10.64Present Value(PVRR)Cumulative PVRRNet Present Value = 1,483,331,874Levelized ($/year) 113,706,7922043 2044 2045 2046 2047 2048 2049 2050 2051 205231 32 33 34 35 36 37 38 39 400.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.672.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.655453,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,037 53,0370000000000802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106 802,106112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432 112,432232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.1276.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.911.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.7517.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.500.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.437972.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850 148,850162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.674200000000000.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.06221.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0051,431,522 50,664,246 49,914,309 49,182,231 48,468,547 47,773,810 47,098,589 46,443,468 45,809,050 45,195,95713,159,313 13,422,500 13,690,950 13,964,768 14,244,064 14,528,945 14,819,524 15,115,915 15,418,233 15,726,597000000000024,261,300 24,807,179 25,365,340 25,936,060 26,519,622 27,116,313 27,726,430 28,350,275 28,988,156 29,640,3903,260,620 3,325,832 3,392,349 3,460,196 3,529,400 3,599,988 3,671,987 3,745,427 3,820,336 3,896,74212,334,425 12,611,950 12,895,719 13,185,872 13,482,555 13,785,912 14,096,095 14,413,257 14,737,555 15,069,15000000000001,150,615 1,176,504 1,202,975 1,230,042 1,257,718 1,286,017 1,314,952 1,344,539 1,374,791 1,405,7231,928,452 1,967,021 2,006,361 2,046,488 2,087,418 2,129,166 2,171,750 2,215,185 2,259,488 2,304,678107,526,247 107,975,231 108,468,003 109,005,658 109,589,323 110,220,152 110,899,327 111,628,065 112,407,609 113,239,23910.10 10.14 10.19 10.24 10.29 10.35 10.42 10.48 10.56 10.6412,500,205 11,710,582 10,975,080 10,289,796 9,651,119 9,055,702 8,500,447 7,982,482 7,499,148 7,047,9831,400,619,534 1,412,330,116 1,423,305,196 1,433,594,992 1,443,246,112 1,452,301,814 1,460,802,261 1,468,784,742 1,476,283,890 1,483,331,874ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB CoalCalendar Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027OperatingYear12 3 4 5 6 7 8 9 10 11 12 13 14 15Annual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort. 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fuel Prices ($/mmBtu)PRB Coal 2.45 2.51 2.57 2.65 2.72 2.79 2.87 2.95 3.02 3.11 3.19 3.27 3.35 3.39 3.47Inflation Factors 1.1149 1.1400 1.1657 1.1919 1.2187 1.2462 1.2742 1.3029 1.3322 1.3621 1.3928 1.4241 1.4562 1.4889 1.5224Variable O&M CalculationsConsumption RatesLime(tons)000000000000000Limestone(tons)483,319 478,220 498,153 498,867 466,645 468,125 418,161 431,954 449,475 483,319 478,220 498,153 498,867 466,645 468,125Total Water Requirement(1000sga 1,033,120 1,022,222 1,064,829 1,066,354 997,479 1,000,643 893,841 923,326 960,778 1,033,120 1,022,222 1,064,829 1,066,354 997,479 1,000,643Waste Ash Disposal(tons)942,733 932,788 971,667 973,059 910,209 913,097 815,639 842,544 876,720 942,733 932,788 971,667 973,059 910,209 913,097Lime, $/ton 119.30 121.98 124.73 127.53 130.40 133.34 136.34 139.41 142.54 145.75 149.03 152.38 155.81 159.32 162.90Limestone $/ton 41.96 42.79 43.65 44.52 45.41 46.32 47.25 48.19 49.16 50.14 51.14 52.17 53.21 54.27 55.36BagCost, $ 121.45 123.88 126.36 128.88 131.46 134.09 136.77 139.51 142.30 145.14 148.05 151.01 154.03 157.11 160.25Total Water Requirement, $/1000gal 0.74 0.75 0.77 0.79 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1.00Waste Ash Disposal, $/ton 9.47 9.66 9.85 10.05 10.25 10.45 10.66 10.88 11.09 11.32 11.54 11.77 12.01 12.25 12.49Calculated ValuesTax Depreciation 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Adjusted for Evaluation Period 7.142% 14.286% 14.286% 14.286% 14.286% 14.286% 14.286% 7.142% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%Fixed Charge Rate 15.27% 14.58% 13.80% 13.01% 12.24% 11.46% 10.68% 10.13% 9.90% 9.76% 9.62% 9.47% 9.33% 9.20% 9.06%O&M Escalation Factor 1.1262 1.1487 1.1717 1.1951 1.2190 1.2434 1.2682 1.2936 1.3195 1.3459 1.3728 1.4002 1.4282 1.4568 1.4859CapacityFactor 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12%Annual Generation(MWh)11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901Aux. Power(MWh)263,510 260,730 271,598 271,987 254,419 255,226 227,985 235,505 245,058 263,510 260,730 271,598 271,987 254,419 255,226Aux. Power Cost($/MWh)66.00 64.92 64.61 67.47 68.81 76.07 84.09 92.96 96.00 99.15 102.39 105.74 109.20 111.66 114.17Fuel Price($/mmBtu)2.4523 2.5125 2.5733 2.6490 2.7193 2.7883 2.8663 2.9469 3.0236 3.1070 3.1871 3.2710 3.3498 3.3946 3.4689Fuel Consumption(mmBtu/year)000000000000000Present Value Factor 0.9329 0.8704 0.8120 0.7575 0.7067 0.6593 0.6151 0.5739 0.5354 0.4995 0.4660 0.4347 0.4056 0.3784 0.3530Evaluation Period Factor 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00Annual Revenue Requirements:Expense TotalsFixed Charges Basis 125,134,966 119,426,508 113,023,540 106,628,884 100,242,788 93,865,510 87,497,314 83,016,452 81,125,259 79,946,372 78,777,708 77,619,573 76,472,282 75,336,161 74,211,545Fixed O&M 8,984,524 9,164,214 9,347,499 9,534,449 9,725,137 9,919,640 10,118,033 10,320,394 10,526,802 10,737,338 10,952,084 11,171,126 11,394,549 11,622,440 11,854,888Fuel000000000000000Aux Power Purchase 17,391,290 16,926,524 17,547,093 18,350,438 17,506,793 19,414,693 19,171,676 21,892,895 23,526,434 26,125,736 26,696,09128,718,843 29,701,150 28,407,864 29,139,187Bag Replacement000000000000000Lime000000000000000Limestone 20,277,675 20,465,048 21,744,405 22,211,062 21,191,978 21,684,389 19,757,342 20,817,252 22,094,887 24,233,698 24,457,627 25,986,576 26,544,275 25,326,375 25,914,852Total Water Requirement 760,238 769,143 819,229 838,861 802,335 822,990 751,690 793,957 844,750 928,794 939,674 1,000,864 1,024,849 980,224 1,005,459Waste Ash Disposal 8,926,919 9,009,407 9,572,623 9,778,062 9,329,427 9,546,203 8,697,851 9,164,459 9,726,918 10,668,495 10,767,076 11,440,171 11,685,689 11,149,528 11,408,596Total Revenue Requirements 181,475,613 175,760,846 172,054,388 167,341,756 158,798,457 155,253,424 145,993,906 146,005,409 147,845,049 152,640,434 152,590,260 155,937,154 156,822,795 152,822,592 153,534,527Busbar ElectricityPrice($/MWh)16.48 16.13 15.16 14.73 14.94 14.56 15.33 14.84 14.44 13.86 14.01 13.74 13.80 14.38 14.40Levelized($/MWh)15.05Present Value(PVRR)169,305,072 152,976,785 139,707,863 126,768,431 112,228,916 102,364,973 89,804,193 83,788,136 79,153,855 76,240,647 71,104,239 67,790,678 63,603,537 57,824,427 54,197,784Cumulative PVRR 169,305,072 322,281,857 461,989,720 588,758,151 700,987,067 803,352,040 893,156,234 976,944,370 1,056,098,225 1,132,338,872 1,203,443,111 1,271,233,789 1,334,837,326 1,392,661,753 1,446,859,536Net Present Value = 2,098,266,524Levelized ($/year) 160,845,4325.32 $/kW-yr fixed4.30 $/MWH variableENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)15.05Present Value(PVRR)Cumulative PVRRNet Present Value = 2,098,266,524Levelized ($/year) 160,845,4322028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 204216 17 18 19 20 21 22 23 24 25 26 27 28 29 300.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%3.55 3.64 3.72 3.79 3.86 3.94 4.01 4.08 4.16 4.21 4.27 4.32 4.38 4.44 4.541.5567 1.5917 1.6275 1.6642 1.7016 1.7399 1.7790 1.8191 1.8600 1.9018 1.9446 1.9884 2.0331 2.0789 2.1256000000000000000418,161 431,954 449,475 483,319 478,220 498,153 498,867 466,645 468,125 418,161 431,954 467,364 467,364 467,364 467,364893,841 923,326 960,778 1,033,120 1,022,222 1,064,829 1,066,354 997,479 1,000,643 893,841 923,326 999,015 999,015 999,015 999,015815,639 842,544 876,720 942,733 932,788 971,667 973,059 910,209 913,097 815,639 842,544 911,611 911,611 911,611 911,611166.57 170.31 174.15 178.06 182.07 186.17 190.36 194.64 199.02 203.50 208.08 212.76 217.54 222.44 227.4456.47 57.60 58.75 59.92 61.12 62.34 63.59 64.86 66.16 67.48 68.83 70.21 71.61 73.04 74.51163.45 166.72 170.06 173.46 176.93 180.47 184.08 187.76 191.51 195.34 199.25 203.23 207.30 211.45 215.671.03 1.05 1.07 1.10 1.12 1.15 1.17 1.20 1.23 1.26 1.28 1.31 1.34 1.37 1.4012.74 13.00 13.26 13.52 13.79 14.07 14.35 14.64 14.93 15.23 15.54 15.85 16.16 16.49 16.820.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%8.92% 8.79% 8.66% 8.52% 8.39% 8.27% 8.14% 8.02% 7.89% 7.77% 7.65% 7.54% 7.42% 7.31% 7.20%1.5157 1.5460 1.5769 1.6084 1.6406 1.6734 1.7069 1.7410 1.7758 1.8114 1.8476 1.8845 1.9222 1.9607 1.999964.42% 66.55% 69.24% 74.46% 73.67% 76.74% 76.85% 71.89% 72.12% 64.42% 66.55% 72.00% 72.00% 72.00% 72.00%9,525,708 9,839,929 10,239,062 11,010,016 10,893,875 11,347,938 11,364,193 10,630,179 10,663,901 9,525,708 9,839,929 10,646,554 10,646,554 10,646,554 10,646,554227,985 235,505 245,058 263,510 260,730 271,598 271,987 254,419 255,226 227,985 235,505 254,811 254,811 254,811 254,811116.74 119.37 122.05 124.80 127.61 130.48 133.41 136.41 139.48 142.62 145.83 149.11 152.47 155.90 159.413.5516 3.6359 3.7216 3.7884 3.8621 3.9365 4.0056 4.0817 4.1585 4.2129 4.2683 4.3249 4.3830 4.4423 4.54220000000000000000.3293 0.3072 0.2866 0.2674 0.2495 0.2327 0.2171 0.2026 0.1890 0.1763 0.1645 0.1535 0.1432 0.1336 0.12461.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0073,098,780 71,998,220 70,910,231 69,835,192 68,773,490 67,725,526 66,691,712 65,672,471 64,668,243 63,679,475 62,706,634 61,750,196 60,810,654 59,888,513 58,984,29812,091,986 12,333,826 12,580,502 12,832,112 13,088,755 13,350,530 13,617,540 13,889,891 14,167,689 14,451,043 14,740,064 15,034,865 15,335,562 15,642,273 15,955,11900000000000000026,614,720 28,111,235 29,909,658 32,885,353 33,270,572 35,437,099 36,286,336 34,706,309 35,599,777 32,515,598 34,343,913 37,995,324 38,850,219 39,724,349 40,618,14700000000000000000000000000000023,611,853 24,878,543 26,405,435 28,961,513 29,229,128 31,056,364 31,722,866 30,267,363 30,970,647 28,218,350 29,732,162 32,812,833 33,469,090 34,138,472 34,821,241918,351 969,989 1,032,044 1,134,721 1,148,014 1,222,770 1,252,074 1,197,554 1,228,384 1,121,963 1,185,050 1,311,043 1,340,541 1,370,704 1,401,54410,394,737 10,952,377 11,624,567 12,749,839 12,867,652 13,672,063 13,965,480 13,324,718 13,634,328 12,422,673 13,089,105 14,445,321 14,734,227 15,028,912 15,329,490146,730,426 149,244,189 152,462,438 158,398,731 158,377,611 162,464,353 163,536,008 159,058,307 160,269,067 152,409,102 155,796,927 163,349,582 164,540,293 165,793,223 167,109,83915.40 15.17 14.89 14.39 14.54 14.32 14.39 14.96 15.03 16.00 15.83 15.34 15.45 15.57 15.7048,322,272 45,853,902 43,701,206 42,357,855 39,511,885 37,813,227 35,510,007 32,221,475 30,289,386 26,872,208 25,627,311 25,067,665 23,556,991 22,144,507 20,823,4631,495,181,809 1,541,035,711 1,584,736,917 1,627,094,773 1,666,606,658 1,704,419,885 1,739,929,892 1,772,151,367 1,802,440,752 1,829,312,961 1,854,940,272 1,880,007,936 1,903,564,927 1,925,709,435 1,946,532,898ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004WHITE BLUFF STATION UNITS 1 AND 2EVALUATION OF WET VS. DRY FGD TECHNOLOGIESAPPENDIX ESL-009510Table E-5: Annual Revenue Requirements - Case 5Case 5 - Wet FGDPRB CoalCalendar YearOperatingYearAnnual Factors and Prices:Input AssumptionsTax Depreciation7-Year Amort.Fuel Prices ($/mmBtu)PRB CoalInflation FactorsVariable O&M CalculationsConsumption RatesLime(tons)Limestone(tons)Total Water Requirement(1000sgaWaste Ash Disposal(tons)Lime, $/tonLimestone $/tonBagCost, $Total Water Requirement, $/1000galWaste Ash Disposal, $/tonCalculated ValuesTax DepreciationAdjusted for Evaluation PeriodFixed Charge RateO&M Escalation FactorCapacityFactorAnnual Generation(MWh)Aux. Power(MWh)Aux. Power Cost($/MWh)Fuel Price($/mmBtu)Fuel Consumption(mmBtu/year)Present Value FactorEvaluation Period FactorAnnual Revenue Requirements:Expense TotalsFixed Charges BasisFixed O&MFuelAux Power PurchaseBag ReplacementLimeLimestoneTotal Water RequirementWaste Ash DisposalTotal Revenue RequirementsBusbar ElectricityPrice($/MWh)Levelized($/MWh)15.05Present Value(PVRR)Cumulative PVRRNet Present Value = 2,098,266,524Levelized ($/year) 160,845,4322043 2044 2045 2046 2047 2048 2049 2050 2051 205231 32 33 34 35 36 37 38 39 400.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%4.64 4.75 4.86 4.97 5.08 5.19 5.31 5.43 5.55 5.672.1735 2.2224 2.2724 2.3235 2.3758 2.4292 2.4839 2.5398 2.5969 2.65540000000000467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364 467,364999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015 999,015911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611 911,611232.56 237.79 243.14 248.62 254.21 259.93 265.78 271.76 277.87 284.1276.00 77.52 79.07 80.65 82.26 83.91 85.58 87.30 89.04 90.82219.99 224.39 228.88 233.45 238.12 242.88 247.74 252.70 257.75 262.911.43 1.47 1.50 1.53 1.57 1.60 1.64 1.68 1.71 1.7517.15 17.50 17.85 18.20 18.57 18.94 19.32 19.70 20.10 20.500.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000%7.09% 6.99% 6.88% 6.78% 6.68% 6.59% 6.49% 6.40% 6.32% 6.23%2.0399 2.0807 2.1223 2.1647 2.2080 2.2522 2.2972 2.3432 2.3901 2.437972.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00% 72.00%10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554 10,646,554254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811 254,811162.99 166.66 170.41 174.24 178.16 182.17 186.27 190.46 194.75 199.134.6444 4.7489 4.8558 4.9650 5.0767 5.1910 5.3078 5.4272 5.5493 5.674200000000000.1163 0.1085 0.1012 0.0944 0.0881 0.0822 0.0767 0.0715 0.0667 0.06221.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.00 1.0058,098,544 57,231,807 56,384,656 55,557,679 54,751,481 53,966,686 53,203,936 52,463,892 51,747,236 51,054,66816,274,221 16,599,706 16,931,700 17,270,334 17,615,740 17,968,055 18,327,416 18,693,965 19,067,844 19,449,201000000000041,532,055 42,466,526 43,422,023 44,399,019 45,397,997 46,419,452 47,463,889 48,531,827 49,623,793 50,740,3280000000000000000000035,517,666 36,228,019 36,952,580 37,691,631 38,445,464 39,214,373 39,998,661 40,798,634 41,614,607 42,446,8991,433,079 1,465,323 1,498,293 1,532,005 1,566,475 1,601,721 1,637,759 1,674,609 1,712,288 1,750,81415,636,080 15,948,801 16,267,777 16,593,133 16,924,995 17,263,495 17,608,765 17,960,941 18,320,159 18,686,563168,491,645 169,940,183 171,457,029 173,043,800 174,702,152 176,433,782 178,240,427 180,123,867 182,085,926 184,128,47215.83 15.96 16.10 16.25 16.41 16.57 16.74 16.92 17.10 17.2919,587,590 18,431,065 17,348,476 16,334,798 15,385,361 14,495,823 13,662,150 12,880,591 12,147,659 11,460,1121,966,120,488 1,984,551,553 2,001,900,029 2,018,234,828 2,033,620,189 2,048,116,012 2,061,778,161 2,074,658,752 2,086,806,412 2,098,266,524ENTERGYARKANSAS WB1-2_DRY VS WET FGD STUDY REV 2A ISSUED 10-9-08Project 12303-004